Even before Spindletop “gushered” in the great Texas oil boom in 1901, rubber chemistry and technology played a key role in the pressure and flow control of hydrocarbons from petroleum reservoirs. This key role for rubber in the oil field continues today, where the cost of construction of an oil or gas well can exceed a billion dollars. Almost all equipment used in downhole drilling and completion operations currently depends on elastomers and other sealing materials to provide steady, reliable performance during service. Although the cost of the individual seals used downhole in a well represents only a fraction of the total well cost, the seals are critical to well performance and safety. Sealing mechanisms are at the heart of any drilling, completion, or production system and are the primary components on which the functional success and longevity of the system rests. Modern drilling systems, with their significant use of onboard electronic components and sensors, rely heavily on nonmetallic seals to prevent well environmental contamination while withstanding sustained dynamic loadings throughout service. Well completion systems can be categorized by either relatively short-term applications, after which seals can be changed or maintained, or long-term applications, in which seals are expected to perform without change or maintenance for 20 years or longer. The assurance of these systems' continued performance throughout the life of the well, whether the expected life is short or long, is of vital importance.

The kinetics of thermal shrinkage of poly(ethylene terephthalate) films have been characterized and related to various parameters of the stretching process. Amorphous orientation functions and levels of crystallinity have been found to be of major importance to the shrinkage process. As film extension ratios increase, shrinkage behavior passes through five different regions. Shrinkage first increases with extension ratio, decreases with further extension to reach a minimum, and then increases again as extension is continued to higher levels. A schematic model has been proposed to describe molecular changes in polymer chain structures, within each of the shrinkage regions. Activation energies of shrinkage have been determined in addition to equilibrium shrinkage and shrinkage rate constants.

Frac packing tool erosion is becoming a growing concern as more high-profile deepwater wells are completed using this technique. Today many deepwater wells require frac pack pump rates of at least 40 barrels per minute (bbl/min) with proppant loads reaching 300,000 lbs. As zone lengths are increased and multi-zone operations are performed jobs requiring 60 bbl/min pump rates with proppant loads reaching 900,000 lbs. may be more typical. The current frac packing tool designs must be optimized to accommodate the higher pump rates and proppant volumes required to complete these deepwater wells. Computational fluid dynamics (CFD) analysis of these systems provides valuable insight to what is physically happening to the tools at these high pump rates and proppant loads. Analyzing various patterns, such as velocity, fluid path, erosion, and sand concentration at high rates helps identify critical areas within the system that require design optimization. CFD analysis is a cost effective alternative to trial-and-error testing, which can cost upwards of $150,000 per test and prolong the development phase. Two sizes of systems have been analyzed using CFD analysis and modified based on the results of that analysis. Full scale tests were also performed at 40 bbl/min on these two systems to compare the actual results with that of the CFD analysis. The CFD analysis was able to generate accurate profiles of the physical erosion patterns observed after the full scale tests were completed. Although CFD cannot accurately predict magnitudes for erosion rates, it can predict erosion profiles and velocity magnitudes. Research is currently ongoing to accurately predict erosion rate magnitudes. This paper will detail the development, analysis and qualification testing of a next-generation frac packing system capable of use in ultra-high-rate operations. Introduction There are currently two major areas of concern in any high-rate crossover tool system, which are used in all conventional frac packing applications. Those two areas are where the fluid, typically a slurry consisting of high-strength proppant in a gelled carrier fluid, rapidly changes direction to transition into a concentric annulus. The first area is a transition from the tubing into the mini-annulus via a ported sub called the Bypass Crossover Sub. Here, the flow exits the bypass sub and impinges upon the inner surface of the Packer Extension. The flow travels down the mini-annulus, formed in between the Service Tool and Packer Extension, until the flow reaches the second area of concern: where the fluid transitions into the annulus from the mini-annulus via a set of ports in the Packer Extension. The fluid exits through these extension ports and impinges upon the ID of the well bore casing. The fluid then travels down the annulus to the formation to induce fracture of the formation and subsequent annular pack. At a volumetric flow rate of 40 bbl/min flow velocities exceed 200 feet per second (ft/s) through the ID of the service tool. As the fluid transitions into the mini-annulus, it impinges upon the ID of the Packer Extension at approximately 45 degrees with velocities upwards of 200 ft/s. At this velocity and impingement angle the abrasive slurry being pumped erodes through the Packer Extension and dramatically alters the shape of the port in the Bypass Crossover Sub. The second area of concern experiences similar problems as the first. The flow exits the ports in the Packer Extension at approximately 140 ft/s and impinges upon the casing ID at a 90º angle. Erosion to these ports could prevent them from being sealed off for later downhole operations, and could compromise the integrity of the casing. To redesign these two areas, a better understanding of the flow dynamics through this area of the system was needed. Highly turbulent flow is difficult to analyze empirically; therefore, CFD analysis was used to validate the design changes.

Generally, horizontally completed oil producers are susceptible to localized gas coning during their life due to the gas/oil contact encroaching the well bore. Even a small difference in permeability and/or relative permeability along the well bore can result in gas coning, which impacts oil production and gas handling issues. Production optimization can be achieved by selectively shutting in areas where gas coning has broken into the wellbore, thus improving drainage efficiency. A new system has been developed to passively sense gas inflow into the well. Once gas is detected in sufficient levels a valve is activated which shuts off the flow path into the well. The valve is designed to detect fluid density changes, and will activate once a predetermined decrease in production fluid density is reached, indicating gas coning. Incorporated in a sand face screen completion, each screen joint includes a phase-sensitive valve that enables it to work independently of the others. This approach has the benefit of shutting off unwanted gas inflow without the need for costly well intervention. Used in conjunction with zone isolation packers to eliminate annular flow, flow normalization can be achieved across the production interval1. The design can also be adapted to shut off water flow, as well as gas, in the event of water coning into the wellbore. This paper will detail the development process of this new passive gas shut-off valve, including laboratory testing performed to qualify the technology. Plans for full-scale two-phase flow testing, conducted in cooperation with a major North Sea operator, will also be discussed. Introduction Controlling inflow into long, extended-reach horizontal wellbores has received significant attention within the past 10 years. A considerable amount of test data and actual field installations have shown that balancing inflow over the entire production interval results in enhanced oil recovery and a delay in gas and water coning2. The advent of the Inflow Control Device (ICD), which is patented by Hydro, has revolutionized the means by which long horizontal wells are produced. The ICD is essentially a flow restriction device integral to each screen joint. By restricting free flow into the screen a normalizing effect is created by which all screen joints contribute equally to the production inflow. The tendency for greater production from the heal of the wellbore is eliminated3. In non-gravel packed applications the ICD also eliminates annular flow around the screens and creates a balanced radial flow regime4. The ICD design best suited for a long service life uses a helical flow channel located in the screen assembly between the filter cartridge and the opening into the screen body. The helical flow channel creates a very precise, and repeatable, pressure drop for a specified fluid density and flow rate. The flow restriction is created by the fluid friction with the walls of the helical channels. The number of channels and their length can vary to create the desired flow restriction. This design maintains fluid flow velocity relatively low, when compared to an orifice-type restrictor, and results in very small erosion potential. This yields a product with a long service life. Typically for horizontal wells in uniform formations the flow normalizing effect created by the ICD delays the onset of gas and/or water coning along the whole horizontal section. However, there are uncertainties with respect to drilling accuracy, and in heterogeneous formations localized gas breakthrough will impair oil production. This is due to many variables such as the static effects of absolute permeability, permeability distribution and geometry (sand thickness and well elevation), dynamic effects of the wells distance to liquid contacts, global moments based on aquifer communication to surrounding aquifers and gas cap, neighboring wells and past production history. To prevent gas influx into the well once initial gas breakthrough does occur, a density-sensitive valve (patent pending) has been designed to compliment the ICD. This enhancement of the existing ICD design is designated Autonomous Inflow Control Device (AICD).

No abstract