In this paper, we present the design of a performance isolation benchmark that quantifies the degree to which a virtualization system limits the impact of a misbehaving virtual machine on other well-behaving virtual machines running on the same physical machine. Our test suite includes six different stress tests -a CPU intensive test, a memory intensive test, a disk intensive test, two network intensive tests (send and receive) and a fork bomb. We describe the design of our benchmark suite and present results of testing three flavors of virtualization systems -an example of full virtualization (VMware Workstation), an example of paravirtualization (Xen) and two examples of operating system level virtualization (Solaris Containers and OpenVZ). We find that the full virtualization system offers complete isolation in all cases and that the paravirtualization system offers nearly the same benefits -no degradation in many cases with at most 1.7% degradation in the disk intensive test. The results for operating system level virtualization systems are varied -illustrating the complexity of achieving isolation of all resources in a tightly coupled system. Our results highlight the difference between these classes of virtualization systems as well as the importance of considering multiple categories of resource consumption when evaluating the performance isolation properties of a virtualization system.
Results of recent field trials with a newly developed fracturing-fluid system and liquid surface-modification additive for coating proppant are presented in this paper. The work was performed in the Underpressured Fruitland Coal (UFTC) gas reservoir in the Northern San Juan Basin of Colorado and New Mexico. This new technology has influenced production in the region. Data of the test-well population are compared to the coal gas and water production from the reservoir. This study identifies and applies the new fracturing system technology for improving production. The results of this study provide information that may apply to other coal-gas reservoirs. The study group of wells uses hydraulic fracturing treatments consisting of a new low polymer loading crosslinked fluid system with a proppant surface-modification additive. The fluid system has increased crosslinked-fluid viscosity, requiring a lower gelling-agent concentration. A liquid additive that coats the proppant and increases its surface adhesion is added in the blender tub during the treatment. The surface friction between the coated proppant grains resists high flow rates during cleanup. Modifying the proppant also influences the migration behavior and blocking effects of fines (coal and precipitates) within the propped fracture.
A novel oxidizing breaker system has been developed for fracturing fluids at high temperatures. Below 200 F, the system is not active, but above 200 F, the oxidizing system aggressively attacks the polysaccharide backbone of the fracturing fluids, resulting in a complete break of the crosslinked fluids. In the presence of a gel stabilizer, an intermediate, reactive oxidizing species is formed. The result of this formation is a delayed, soluble, high-temperature oxidizing system. Controlled viscosity reduction at 200 F to 300 F in crosslinked gelled fluids with and without a gel stabilizer will be demonstrated. Testing included Model 50 viscosity profiles, high-temperature static break tests, and conductivity testing. Results from all testing showed the effect of oxidant concentration in producing a predictable, controlled break of the thermally stabilized crosslinked systems. Data were obtained in low-pH and high-pH Zr-crosslinked fluids as well as in borate-crosslinked fluids. The delayed mechanism of the new breaker system provides fluids with excellent crosslinked viscosity properties at early times with predictable, long-term viscosity reductions. Case histories show that the breaker system can be used throughout the treatment in the pad fluid, proppant-laden fluid, and flush. This paper provides data that allow significant improvements in job design. The operations engineer can obtain predictable, controlled gel degradation by using the data provided for temperature, gel type, gel stabilizers, and breaker concentration. The results are optimized treatment designs with rapid fluid recovery, improved proppant-bed conductivity, and increased well productivity. Introduction Breakers are an essential component of fracturing fluids. Ideally, a breaker should maintain high viscosity throughout the pumping of the fluid and sand. Once pumping is complete, the fluid should immediately break back to the viscosity of water. An ideal viscosity profile is shown in Fig. 1. In most cases, current technology provides a quick initial drop in viscosity followed by a slow, gradual decline in viscosity until the fluid is completely broken. Encapsulation helps achieve an improved break profile at low to moderate temperature, but above about 175 F, diffusion from the capsules becomes the determining factor because the breakers are only briefly stable at those temperatures. Improved fluids technology has provided crosslinked gels that can maintain viscosity at elevated temperatures for long periods of time. These thermally stable fluids improved overall gel viscosity and the ability of the fluid to carry proppant. However, the advancement in fluids technology to provide more stable fracturing gels limited the recovery of the fluid and ultimately the fracture conductivity. The use of breakers in high-temperature fracturing applications would provide a method to efficiently recover these thermally stable fluids. Even today, the need for breakers throughout an entire fracturing treatment above 200 F is not a generally accepted concept because of the lack of controllable breaker systems at these high temperatures. Oxidizing breakers, such as persulfate, are effective from about 120 F to about 175 F. However, these materials react too quickly at higher temperatures. The rapid oxidation causes uncontrolled breaks and premature gel degradation, which lead to the following:–poor proppant transport–insufficient fluid leakoff control–limited ability of the fluid to maintain fracture geometry Encapsulation technology can provide slow release of oxidant, providing a delay in the breaking process. However, these methods offer only limited control above 175 F, especially above 200 F and when gel stabilizers are required. Enzymes are the other major class of gel breakers. Typically, the application of enzymes is limited to lower temperatures (150 F or lower) and an optimized pH range (5 to 8). P. 175^
This paper describes the development and testing of a solid, encapsulated scale inhibitor for use in fracturing treatments. Data from laboratory and field tests are reported. Laboratory testing with a continuous flow apparatus has yielded inhibitor release rates under dynamic conditions. The inhibitor was tested to determine the minimum inhibitor concentration required to inhibit the formation of CaCO3, CaSO4, and BaSO4 scales in brine. Laboratory data were used to determine the parameters of a mathematical model to predict the long-term release rate of the inhibitor. Data from a treated well are compared with predictions of the model. Release-rate testing in a continuous-flow apparatus shows that an encapsulated solid derivative of a phosphonate inhibitor has a sustained release profile. Temperature (100 to 225 F) and brine strength have a small effect on the release-rate profile. Coating the solid derivative makes it compatible with metal-crosslinked fracturing fluids. The coating has a short-term effect on the release-rate profile. The composition of the solid derivative has the greatest effect on its long-term release-rate profile. A comparison between the mathematical model proposed to describe the long-term release rate of the inhibitor and actual data collected from a treated well shows a large discrepancy, likely because most of the inhibitor is not in contact with the water being produced from this well. Introduction A variety of scale inhibitors are available for use in oilfield applications, including polyphosphate phosphate ester, phosphonate polyacrylic acid, and polyacrylic acid derivative inhibitors. Most of these inhibitors are available as liquids and can be applied by continuous addition or in squeeze treatments. Polyphosphate inhibitors appear to be one of the few types available in a solid form that can be combined with a hydraulic stimulation treatment. A solid inhibitor that can be applied in conjunction with a fracturing treatment allows two treatments to be combined, saving the operator time and possibly expense. The objective of this paper is to describe our work in developing and testing a solid scale inhibitor for use in fracturing treatments for wells with BHSTs up to 225 F. Several inhibitors were screened before three candidates were chosen. These three inhibitors were tested to determine (1) their effectiveness to inhibit commonly occurring oilfield scales and (2) their release-rate profiles in continuous flow-release experiments. A mathematical model was used to describe the release-rate profiles and to predict the long-term behavior. Compatibility testing showed that solid derivatives of these inhibitors interfered with metal-crosslinked fracturing fluids. To abate this interference, a semipermeable membrane was used to coat the solid derivatives. The following data is presented for the solid derivative chosen for field testing:–effect of the coating on a release-rate profile–effect of brine strength on a release-rate profile–minimum effective dosage of inhibitor required to inhibit scale formation for calcite, gypsum, and barite scales Results for one field trial are reported and compared to the mathematical model. Experimental Equipment. The test system used to determine the release rate of inhibitors is shown in Fig. 1. The system consists of an isolated reservoir of brine that supplies the test column. The reservoir is made from Ampcoloy, and all tubing in the system consists of stainless steel or nylon tubing. Several 12-in. columns of 0.75-in. OD stainless tubing were used for testing. Nitrogen was used to maintain the system pressure at approximately 200 psi. P. 557
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