Evenly distributed production along the length of the wellbore is important for maximizing the oil recoverables over the life of the well. Traditional, passive in-flow control devices (ICDs) perform well at balancing the completion pressure differential with the reservoir pressure differential so that an even influx across production zones is maintained. This helps to delay unwanted fluid break through. When unwanted fluids, typically of lower viscosity, do finally break through, they can take over the well, significantly reducing the production of oil. Autonomous Inflow Control Devices (AICDs) are a new generation of ICDs. When oil is producing from all zones, the AICD will behave as a passive ICD, balancing flow. However, when lower viscosity (undesired) fluids break through, the AICD chokes them, significantly reducing flow from the zone producing these fluids. This autonomous function enables the well to drain the oil producing zones faster than the undesirable fluid zones, thereby maximizing total oil production. The AICD creates this change in behavior without control lines, moving parts, or electronics.The paper describes the laboratory testing performed to evaluate the performance of the fluidic diode type AICD Range 2A in field-like conditions and compares flow performance curves to a traditional nozzle type ICD. The AICD Range 2A utilizes similar fluid vectoring as the Range 3B (Least et al, 2013), but includes more of an autonomous on/off type switching function instead of a gradual change in performance. The range 2A is currently best suited for oil viscosities of 1.5-10 cP. Results from single-phase experimental flow testing with model oil, water, and nitrogen are presented and discussed.The test results demonstrated that the AICD could restrict flow rates of undesirable fluids. The discussion further shows that if technology such as the new AICD is applied to new well completion designs, total oil recovery can be enhanced, by increasing the life of the well and reducing production of undesirable fluids.

Reservoir inflow control is important for maximizing hydrocarbon production. Traditional in-flow control devices (ICDs) attempt to balance the completion pressure differential with the reservoir pressure differential so that a balanced influx across production zones is maintained. This maximizes oil production by delaying unwanted fluids from breaking through. Unfortunately, when lower viscosity fluids do break through, they can take over the well, significantly reducing production of the desired hydrocarbon. Autonomous Inflow Control Devices (AICDs) are a new generation of ICDs. When hydrocarbons are producing from all zones, the AICD will behave as a traditional ICD, balancing flow. However, when low-viscosity (undesired) fluids break through, the AICD chokes them, significantly slowing flow from the zone producing the undesirable fluids. This autonomous function enables the well to continue producing the desired hydrocarbons for a longer time, maximizing total production. The AICD creates this change in behavior without control lines, moving parts, or electronics. The paper describes the laboratory testing performed to evaluate the performance of the fluidic diode type AICD Range 3B in field-like conditions and compares flow performance curves to a traditional nozzle type ICD. The fluidic diode AICD Range 3B is similar to the original design now referred to as the Range 3A (Least et al, 2012) in that it is best suited for oil viscosities of 3-200 cP but has slightly more open flow paths which allow for increased flow rates in turn allowing fewer inserts per screen joint while keeping similar performance ratios. Results from single-phase experimental flow testing with model fluids and crude oil are presented and discussed. The testing results proved that the AICD could restrict flow from zones producing undesirable fluids. The discussion further shows that if technology such as the new AICD is applied to new well completion designs, total hydrocarbon recovery will be enhanced, providing a significant benefit for production companies and those involved in design and modeling of new well completions.

This paper describes the methods developed for testing and qualification of novel lightweight drilling fluids (foams, glass-bead fluids) using a unique pilot-scale test facility (PSTF). The performance criteria included fluid stability, rheology, pressure transmission, and gas migration under downhole conditions. Test results demonstrating the methods developed are provided, along with the capabilities of the facility, custom fixtures, and equipment that were built to study the performance of these fluids. A set of performance criteria and testing requirements were initially developed, which were then used to design and fabricate a novel pilot facility. The PSTF could generate downhole drilling conditions of 7,500 psig and temperatures above 300°F. Three custom-instrumented test articles were built to simulate wellbore geometry; one 10-ft long and one 18-ft long, both with a 2.62-in ID. The third article had a 10-ft long 6-in × 4-in annulus, with the eccentric internal pipe capable of 100-rpm rotation to mimic the drill string. The test articles could incline up to 45° to simulate deviated wells. Gas could be injected, and its migration rate measured in static and countercurrent flow using a video camera with full-bore sight glass, and gamma-ray densitometers. Dedicated sections for foam generation, measuring density, rheology, pressure transmission, and fluid sampling and imaging were provided. Upon commissioning of the PSTF, a 1 1/2 year test program was successfully carried out using lightweight foams and hollow glass-bead fluids. Due to the novel nature of the tests, best practices and procedures were developed through experimentation to quantify static and dynamic fluid stability, gas migration, foam generation techniques, fluid imaging and characterization, pressure transmission, and rheology. A variety of measurement techniques and instrumentation were trialed in the test articles to determine the best methods for tracking gas migration. Experiments in the test articles yielded a large amount of performance data, including fluid stability over time at different temperature and pressure conditions, the impact of drill string rotation on fluid stability, migration velocities of gas bubbles (i.e., gas kicks) within the drilling fluids at stagnant and countercurrent flow conditions, and the impact of drill string rotation. Pressure transmission speeds were measured in the foam with varying gas fractions. Example datasets from the testing program are provided, along with detailed descriptions of the test methods. The methods and test facility used to study lightweight drilling fluids are unique to the authors’ knowledge. For the first time, drilling fluids were analyzed in an annulus with a rotating pipe at downhole conditions at a pilot scale, and fluid stability along with gas migration were studied. These provide for rigorous testing of lightweight drilling fluids; the application of these fluids is expected to increase with declining reservoir pressures in oil and gas fields.

Using foams to drill in low pore pressure reservoirs is attractive because of their low density, high viscosity, and ability to transport cuttings. However, in high temperature reservoirs (240 °F) with H2S gas present, there are concerns with the long-term stability of a foam drilling fluid. In this work, we highlight a lab program to develop a stable drilling foam for drilling in a low pore pressure, high temperature reservoir. The work also includes pilot-scale experiments to evaluate foam performance. Aqueous nitrogen-in-water foams were stabilized with a preferred foaming surfactant formulation, and the rheology and stability of the foams were measured at representative drilling conditions (temperature and pressure) at the lab and pilot-scale. The foams were also evaluated for their compatibility with current drilling fluids used on site and for stability in the presence of H2S gas (at 1900 psi and 140 °F). The drilling foam was also evaluated using a pilot-scale flow loop comprised of a rheology flow loop and a model drilling wellbore. The experiments included measuring the foam rheology, foam stability in the model wellbore, and gas migration tests to understand how the foam suppresses upwardly migrating gas bubbles. We successfully developed a surfactant stabilized foam designed for a high-temperature reservoir with H2S gas present. We found that H2S can negatively impact foam stability if proper surfactants are not selected. Our foam showed less than 10% liquid drainage after 12 hours at 240 °F and showed no significant degradation upon contact with 17 mol% H2S gas. Additionally, the foam was compatible with all drilling fluids (both water-based and oil-based) currently used at the drill site and demonstrated good stability in a model pilot-scale drilling wellbore. Interestingly, when the wellbore was angled at 30 degrees from vertical with the eccentric drill pipe rotating at 100 RPM, the foams were susceptible to degradation compared to an equivalent scenario of a vertical wellbore with concentric rotating drill pipe. The gas migration tests at the pilot-scale showed the foam was capable of significantly slowing down an upwardly moving gas bubble with and without pipe rotation.

Gas migration velocity impacts the planning of pressurized mud cap drilling (PMCD) as it plays a pivotal role in the selection of fluid volumes and logistics. A pilot-scale experimental investigation of gas migration under downhole conditions (up to 3,600 psi, 240°F) in water, oils, and low-density drilling fluids is presented. While bubble-rise phenomena have been studied at near atmospheric pressures, the experimental setup and measurement method for high-temperature, high-pressure gas migration is rare. Experiments were performed using three test apparatuses: two separate pressurized lengths of 3-inch pipe, one 10-ft long and the other 18-ft long, as well as a unique high-pressure, high-temperature rotating test section (RTS). The RTS is 10-ft long, having a 6 inch × 4 inch eccentric annular geometry with the inner pipe capable of rotation. The inclination of all test sections can be varied. Gas was injected from the bottom through either a 1/8-inch diameter pressurized-injection port or a liquid-gas swap mechanism i.e. zero-velocity injection. Gas migration was recorded using a camera system or gamma-ray densitometers (GRDs). Some of the key results and insights from the testing are: (1) the gas migration rate and bubble length decrease with an increase in pressure, (2) the gas migration rate is higher in inclined vs. vertical sections, (3) bubble breakup occurs as pressure increases and interfacial tension decreases, (4) the inclination of the fluid column delays bubble breakup, and (5) high viscosity hinders bubble breakup. A key observation from the testing was that Taylor bubbles that may form during the initial phase of gas entering the annulus are likely to break up under downhole conditions of high pressure, low interfacial tension, and typical field mud viscosities, resulting in much lower gas migration rates during PMCD than the commonly used industry correlations. Another observation was that the practical length limitation of the test articles prevents us from observing the full evolution of gas bubble breakup. The results seen here are in line with our previous simulation work (Samdani et al., 2021, 2022).