Parallels Desktop for Mac. Run Windows on Mac. A fast, easy, and powerful application for running Windows on your Intel or Apple M Series Mac—all without. Parallels Desktop – Run Windows on Mac without Rebooting! Easy to Get Started. Instant Download. Try Free Today!
 
 

 

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Parallels Desktop for Mac is software providing hardware virtualization for Macintosh computers with Intel processors, and since version It is developed by Parallels , since a subsidiary of Corel. Parallels, Inc. Released on June 15, , it was the first software product to bring mainstream virtualization to Macintosh computers utilizing the Apple—Intel architecture earlier software products ran PC software in an emulated environment.

On January 10, , Parallels Desktop 3. Parallels Desktop for Mac is a hardware emulation virtualization software, using hypervisor technology that works by mapping the host computer’s hardware resources directly to the virtual machine’s resources.

Each virtual machine thus operates identically to a standalone computer, with virtually all the resources of a physical computer. For example, a running virtual machine can be stopped, copied to another physical computer, and restarted.

Parallels Desktop for Mac is able to virtualize a full set of standard PC hardware, including [5]. Version 2. This version also allowed users to boot their existing Boot Camp Windows XP partitions, which eliminated the need to have multiple Windows installations on their Mac.

Additionally, the lawsuit claimed that Parallels Desktop 2. Version 3. Support for DirectX 8. Parallels Explorer was introduced, which allows the user to browse their Windows system files in Mac OS X without actually launching Windows. A new snapshot feature was included, allowing one to restore their virtual machine environment to a previous state in case of issues. Further, Parallels added a security manager to limit the amount of interaction between the Windows and Mac OS X installations.

Despite the addition of numerous new features, tools and added functionality, the first iteration of Parallels Desktop for Mac 3. A Parallels, Inc. Also, SCSI support has not been implemented.

It is currently unknown if these features have been abandoned altogether, or if they will show up in a later build of version 3. Build , released on July 17, , [14] added an imaging tool which allowed users to add capacity to their virtual disks. Build , released on September 11, , [15] added some new features and updated some current features.

Further, Parallels’ Image Tool was updated to allow one to change their virtual hard disk format between plain and expanding. Parallels Explorer was updated to allow for one to automatically mount an offline VM hard drive to the Mac desktop.

Some new features added are iPhone support in Windows, allowing iTunes in Windows to sync with it. According to Parallels’ Licensing page, Desktop for Mac version 3.

Parallels released the modified source code on July 2, , about 2 weeks after the promised release date. Version 4. Parallels Desktop 4. Starting with the Version 4. Build , released January 9, , [27] includes performance enhancements and features, such as DirectX 9.

Also included are usability features such as the ability to share Windows files by dragging them directly to a Mac application in the Mac Dock.

Windows can now also automatically start in the background when a user opens a Windows application on the Mac desktop. Officially released on November 4, , Parallels Desktop 5 adds several new features, mainly to improve integration with the host OS.

Build , released on December 21, , added some new features. Officially announced on September 9, and launched on September 14, , Parallel 6 has full bit support for the first time. Officially announced on September 1, and released on September 6, , Parallels Desktop 7 adds many new features.

These include:. Officially announced August 22, and released September 4, , Parallels Desktop 8 adds many new features:. Officially announced on August 29, and released on September 5, , Parallels Desktop 9 for Mac includes these new features and enhancements:. Less than a year after release of its release, Parallels spokesperson John Uppendahl confirmed version 10 will not be fully compatible with Windows The coherence mode, which integrates the Windows user interface with OS X, will not be updated and users will need to purchase and upgrade to version 11 to continue using this feature.

The website currently offers a full price upgrade to Version 13 as a correction, effectively making this version obsolete with the macOS upgrades.

Released August 18, It is also the first solution to bring the upcoming Windows 10 People Bar feature to the Mac, including integration with the Mac Dock and Spotlight. The new version also features up to percent performance improvements for completing certain tasks.

The update also brings in a slightly refreshed UI to better match macOS and visual improvements for Windows users on Retina displays. Released August 11, On April 14, , Parallels updated the software to version OS X Therefore, a High Sierra guest machine must be installed ‘manually’ by passing the “–converttoapfs NO” command line switch, and cannot use the automated Parallels virtual machine creation process.

C Versions are partially compatible with the corresponding macOS versions and may not work correctly. Parallels Desktop 16 for Mac includes support for a variety of different guest operating systems: [47]. In Parallels Desktop 10 for Mac, support for guest operating systems includes a variety of bit and bit x86 operating systems, including: [46].

From Wikipedia, the free encyclopedia. Virtual machine. Apple—Intel architecture Apple M1. This section needs to be updated. Please help update this article to reflect recent events or newly available information. November Retrieved The Official Parallels Virtualization Blog. Archived from the original on Archived from the original PDF on Parallels Web. Virtual Strategy. SWSoft Parallels. Inside Mac Games. Ars Technica. Official Parallels Blog. Parallels Desktop Watch Archived at archive.

The official Wine Wiki. O’Grady’s PowerPage. Virtualization Report. The Mac Observer. Parallels Knowledge Base. Archived from the original on 14 April Retrieved 4 July August 21, Retrieved August 24, Parallels Blog.

April 14, Retrieved November 4, Virtualization software. Comparison of platform virtualization software. Docker lmctfy rkt. Rump kernel User-mode Linux vkernel. BrandZ cgroups chroot namespaces seccomp.

Hidden categories: Webarchive template archiveis links All articles with dead external links Articles with dead external links from January Articles with short description Short description matches Wikidata Wikipedia articles in need of updating from November All Wikipedia articles in need of updating. Namespaces Article Talk. Views Read Edit View history. Help Learn to edit Community portal Recent changes Upload file. Download as PDF Printable version.

June 15, ; 16 years ago See also: List of emulators.

 
 

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The proper selection, design, and installation of tubing string are critical parts of any well completion.

See the chapter on inflow and outflow in this section of the handbook for more information. Tubing strings must be sized correctly to enable the fluids to flow efficiently or to permit installation of effective artificial lift equipment.

A tubing string that is too small causes large friction losses and limits production. It also may severely restrict the type and size of artificial lift equipment. A tubing string that is too large may cause heading and unstable flow, which results in loading up of the well and can complicate workovers. The planned tubing must easily fit inside the installed casing.

When selecting the material, environmental conditions, the projected corrosivity of the well fluids, the minimum and maximum pressures and temperature, safety aspects, and cost-effectiveness must be considered. The tubing must be designed to meet all stresses and conditions that occur during routine operation of the well and should have an adequate margin for unusual load conditions.

It must withstand the stresses caused by tension, burst, and collapse, and it must resist the corrosive action of well fluids throughout the well life. In addition, the tubing must be handled and installed so that the tubing produces the well without failure or without causing undue operating problems.

This effort continues, and many of these documents with modifications have become International Organization for Standardization ISO documents. Currently, API and ISO are the international standards for products intended for worldwide use in the petroleum and natural gas industry.

API tubing sizes range from ODs of 1. In addition to API steel tubing, there are hostile well conditions that may be better served by other materials. There are proprietary steel grades that do not conform to all aspects of the API specifications but are used in the petroleum-producing industry for resistance to weight-loss corrosion, higher strengths, less susceptibility to sulfide stress corrosion cracking SSC , and wear resistance.

Corrosion-resistant alloy CRA is a special material that is sometimes used in hostile environments. These special materials are usually expensive but may prove worthwhile over the life of the well; however, CRA tubing does not always eliminate corrosion and may be incompatible with some completion fluids.

Most thermoplastic tubing has good tension properties and burst resistance, but has relatively small collapse-pressure resistance and poorer wear resistance properties than steel tubing. Other metals and materials have been used as tubing but rarely are used in current oil and gas completions either because of their cost or because of limited applicability.

API has numerous manufacturing requirements for tubing. For tubing used in sour wells wells with H 2 S content greater than 0. When placing orders for tubing to be manufactured in accordance with API Spec.

API tubing specifications contain several provisions that are optional for the purchaser and other stipulations that are by agreement between the purchaser and the manufacturer. API developed specifications for three different connectors for use as tubing joints: external-upset tubing and coupling, non-upset tubing and couplings, and integral-joint tubing.

The API external-upset-end EUE tubing connection is widely used because it is a good, serviceable connection in most wells. API integral-joint tubing is available in OD sizes of 1. API integral-joint tubing has a round form with a joint strength that is less than the body minimum yield, which restricts its use.

The small OD of integral-joint tubing permits its use inside larger tubing strings or in wells as unloading or vent strings. See API Spec. The couplings should meet all the minimum requirements outlined in API Spec.

Tables showing EUE tubing thread gage, NUE tubing thread gage, and integral-joint-tubing thread gage dimensions will be found in those sources. These joints are useful when greater leak resistance or more clearance is needed than that provided by the standard API joints.

These specialty joints obtain their improved properties through unique thread profiles, a torque shoulder, metal-to-metal seals, seal rings, internal upsets, external upsets, integral joints, etc. Tubing reference tables, which summarize the available non-API tubing joints and tubing, are published yearly in trade magazines such as World Oil.

Many operators commonly use these proprietary connections in critical wells. Before ordering or using a specific proprietary tubing connection in a critical well, the suitability of such a connection for a particular application must be assessed by either a review of service history or a comprehensive connection test program such as ISO For information on workovers with coiled tubing, review the chapter on workover design and procedures in the Drilling Engineering section of this Handbook.

Tubing made to API specifications uses seamless or electric-weld processes. Seamless pipe is defined as a wrought steel tubular product made without a welded seam. It is manufactured by hot-working steel or, if necessary, by subsequently cold-finishing the hot-worked product to produce the desired shape, dimensions, and properties. Because of the nature of the manufacturing, the cross section of the tubing wall area may be slightly eccentric and the tubing slightly oval and not perfectly straight.

Electric-welded pipe has one longitudinal seam formed by electric-resistance or electric-induction welding without the addition of filler metal.

The edges to be welded are pressed together mechanically, and the heat for welding is generated by the resistance to flow of electric current. Such differences are usually eliminated if the electric-weld tubing is heat-treated by the quenched-and-tempered process, which is mandatory for API grades L80, C90, T95, and P Couplings usually are made of seamless tubular product of the same grade and type as the pipe.

API standardized several grades of steel that have different chemical content, manufacture processes, and heat treatments and, therefore, different mechanical properties.

API organized these tubing grades into three groups. Group 1 is for all tubing in grades H40, J55, and N Group 2 is for restricted-yield tubing grades L80, C90, and T Group 3 is for high-strength tubing in seamless grade P The API grade letter designation was selected arbitrarily to provide a unique name for various steels.

Numbers in the grade designation indicate the minimum yield strength of the steel in thousand psi. API defines the yield strength as the tensile stress required to produce a specific total elongation per unit length on a standard test specimen. API Spec. The following guidelines apply to the use of API tubing grades. API products tubing, pup joints, and couplings should be stenciled or a combination of stamping and stenciling as per API Spec.

Impact test temperature, heat treatment, supplementary requirements, type of thread, and plating of coupling are included if applicable. API acknowledges two tubing length ranges: Range 1 from 20 to 24 ft and Range 2 from 28 to 32 ft. Range 2 is normally used. A complete set of tubing pups with the same connections as the tubing string typically is purchased for each well.

API requires that plain-end pipe be tested only to 3, psi maximum, except by agreement between the purchaser and the manufacturer. Various tubing grades and sizes can be tested hydrostatically to higher values as listed in API Spec. The API hydrostatic test pressures specified are inspection test pressures.

They do not necessarily have any direct relationship to working pressures but should be considered when establishing design factors. Care should be taken if test pressures are to be exceeded in well operations. The following equation is used to determine the maximum hydrostatic test pressure.

A maximum test pressure during manufacturing of 10, psi is imposed because of test equipment limitations. The hydrostatic test pressures are calculated from Eq. The lower pressures are based on formulas given in API Bull.

Tubing string design must consider all reasonably anticipated loads imposed during running, producing, stimulation, workovers, and pulling operations. The design must ensure that failures will not occur under these operations; however, the designer typically selects the most economical weight and grade that meets the performance requirements.

Computer software is available for tubing design, but the designer must ensure that all design conditions are met adequately. A reasonable approach must be taken to prevent overdesign. The design need not prevent worst-case scenario failures but rather for all cases that have a reasonable probability of occurring. For instance, assume that there is a shallow tubing leak in which the shut-in tubing pressure is applied in the casing annulus on top of a column of heavy annulus fluid and, subsequently, that the tubing pressure at bottom is reduced quickly to a low value.

This event would require tubing with a very high collapse pressure rating. If such a condition is considered to have a reasonable probability of occurring, the tubing string should be designed accordingly or adequate steps should be taken to prevent such a series of events. The highest tensile loads normally occur at or near the top surface of the well. Collapse loads reduce the permitted tension loads, as shown by the biaxial graph in Fig.

Fortunately, the casing annulus pressure is normally low at the surface; thus, collapse pressure effects at the surface often can be ignored, but not in all cases. Buoyancy, which reduces the tensile loads, is sometimes ignored on shallow wells, but it should be considered on deeper wells.

A condition that frequently determines the required tension yield strength of the tubing occurs when unsetting a partially stuck packer or using a shear-pin-release type packer in wells in which buoyancy is not applicable. High-burst tubing loads typically occur near the surface with little or no annulus pressure under shut-in tubing conditions or during well stimulation treatments down the tubing.

High-burst conditions also may occur deep in the hole with high surface pressures imposed on top of relatively high-density tubing fluid and when the annulus is empty or contains a light-density annulus fluid.

Both of these conditions must be evaluated during the design of a tubing string for a specific well. The burst resistance of the tube is increased because of tension loading up to a certain limit. In tubing- and casing-design practice, it is customary to apply the ellipse of plasticity only when a detrimental effect results. For a conservative design, this increase in burst resistance normally is ignored. Compression loads reduce burst resistance and must be considered when they occur.

Such a condition can occur near the bottom of the well with a set-down packer and a relatively high internal tubing pressure and a relatively low annulus pressure. A typical design case in burst is to assume that the tubing is full of produced fluid and that the annulus is empty, which is a common situation for pumped wells. Because tension loading reduces collapse resistance, the biaxial effect should be used to design for problem regions.

A common practice in tubing design is to assume that the tubing is empty and that the annulus is full of fluid. Such conditions are common in low-pressure gas wells or oil wells that may be swabbed to bottom.

Typically, the highest collapse pressures are near the bottom of the well. For combination tubing-string design, the collapse and tensile loads should be evaluated at the bottom and top of any tubing size, weight, or grade change. Current design practice considers the detrimental effects of tubing bending, but the favorable effect friction while running is neglected. Wall friction, which is unfavorable for upward pipe movement, generally is compensated for by addition of an acceptable overpull to the free-hanging axial tension.

Overpull values are best obtained from field experience but can be calculated with available commercial software computer programs. Thus, it is not possible to mix different sections of the tubing during running or pulling operations throughout the life of the well.

As the pressures and depths increase, there comes a point at which a higher grade stronger or heavier weight increased wall thickness tubing must be used to meet load conditions and achieve acceptable design factors. For the same size diameter tubing, a higher grade normally is preferred over an increase in tubing weight. Such a choice is usually less expensive and maintains a constant internal diameter, which simplifies wireline operation inside the tubing.

Unlike casing design, which often has numerous grades and weights in a combination design, tubing design seldom has more than two different grades or weights. Such restriction may increase the cost of the tubing string but simplifies the running and pulling procedures.

Deep and high-pressure wells may require more than two weights, grades, or diameters. When more than one grade or weight are used, each should be easily identifiable. To separate different weights and grades, a pup joint or different collar types may be used. For example, one section could use standard couplings and another could use beveled couplings. Painted and stenciled markings on the outside of the tubing are inadequate once the tubing is used because such markings are often obliterated.

The use of two or three different diameter sizes is sometimes advantageous. The larger tubing size may have high-joint-yield strength and permit a higher flow rate. The largest diameter is run on the top and a smaller tubing size on bottom. In such cases, the surface wellhead valves often are sized to permit wireline work in the larger tubing to prevent operational problems. A smaller tubing OD size on bottom may be necessary because of casing diameter restrictions.

The tubing OD must have adequate clearance with the casing ID. The tubing size selected should permit washover and fishing operations, in case the tubing becomes stuck and requires recovery.

Nevertheless, special circumstances may require special proprietary tubing in close tolerance applications. Special wash-pipe sizes often can be rented from the tool service companies. The tubing designer should check the success of washover and fishing operations for their particular planned condition and the area of operation.

If two tubing strings are to be run and pulled independently, the sum of the tubing coupling ODs should be less than the casing drift diameter. For example, inside In such a case, beveled and special-clearance couplings with an OD of 2.

The sum of the two ODs is 5. Experience shows that if the couplings are beveled top and bottom , these strings can be run and pulled independently.

The auxiliary tubing equipment such as gas lift mandrels and safety valves often cause more clearance problems than the tubing couplings. If two tubing strings are to be run clamped together, then the sum of the smaller tubing body OD and the OD of the coupling of the second or larger string must be less than the casing drift diameter.

In these cases, a full-size drawing of the cross sections of the tubulars used may be helpful. The actual clearance may depend on the clamp design. Tubing performance properties are found in API Bull. Example 3. The well is to be completed with compression-set type packer and 9. An overpull to free the packer of 15, lbf is anticipated. A maximum surface-treating pressure of 3, psi is expected. Smaller OD sizes of tubing will save no significant investment and will complicate wireline work.

Select the lightest standard weight available for the initial design and check to ensure that it meets all design conditions. The J55 grade is the most cost-effective grade available. It typically is used as a first selection for most relatively shallow, low-pressure, and low-rate design cases. Calculate the fluid gradient, g f. Check design conditions for tension. Calculate the resulting hook load for a 9,ft length of tubing in air from This calculation results in a superimposed tubing tension axial hook load at the surface in air of 42, lbf.

The weight of the tubing string in a fluid is the tubing weight in air minus the axial buoyancy load s Compare these values to the tubing performance properties.

Consider pulling conditions. With a stuck packer requiring 15, lbf of overpull, F op , at packer to free, assume no buoyancy contribution because the packer is stuck.

An overpull any greater than 15, lbf would not be acceptable because D t would be less than 1. Check burst and collapse loads and compare to the tubing performance properties. The maximum allowed internal pressure differential is Assume an annulus full of 9.

With Eq. Check burst at bottom of hole under pumping conditions. Assume tubing filled with 9. Select and order tubing material.

Order per API Spec. In addition, order one container of API-modified thread compound and specify delivery date and shipping instructions. Select the tubing weight and grade. Because surface pressures of 10, psi are anticipated, the tubing must have a minimum internal-yield pressure greater than 10, psi. With a design factor of 1.

Because the partial pressure of H 2 S is 0. Investigate tension load conditions. Use Eq. Buoyancy is neglected because the packer is set. Check collapse conditions. Assume the casing annulus is filled with 14 ppg fluid with no surface pressure and the tubing pressure is bled off after a plug was set in the bottom of the tubing or a tubing safety valve at bottom is closed, which is a reasonable possibility over the life of the well.

Select and order the tubing material. Request that the tubing meet API Spec. In addition, order all accessories with the same connection and an appropriate thread lubricant. Make a dual grade tubing-string design to reduce cost.

The well is relatively straight with small drag forces while pulling, and it is to be circulated with salt water before pulling tubing. Solution Select tubing size. Smaller tubing sizes would result in high friction losses and loss in production rate.

Larger tubing sizes would not increase production rates sufficiently and would result in clearance problems inside the 7-in. Select tubing weight and grade. Check collapse on bottom. Check burst at bottom. Assume casing annulus is empty and tubing is full of produced water. This is possible under gas lift conditions if the annulus injection pressure is bled off with tubing full of produced fluid plus surface wellhead pressure.

With a maximum stimulation burst pressure at surface of 5, psi, use Eq. Check tension loads at surface. Use Eqs. The recommended design factor for weight in air is 1. A higher grade at top must be used for adequate tension design conditions.

Check worst possible tension design case. Pull at surface to overcome drag and shear pins in packer with no buoyancy effect on tubing above packer.

Suggest the use of as much J55 as feasible to reduce tubing string cost. Do not exceed the 50,lbf overpull load, because this would over load the top of the J55 tubing.

Request that tubing meet API Spec. Specify delivery date and shipping instructions. Both these options increase the cost of the tubing string but may increase the operating life. Order the tubing to API 5CT specifications, adding a few hundred feet of each type: seamless, range 2, and a proprietary connection integral joint or threaded and coupled with metal-to-metal seals. Order an appropriate thread compound. All auxiliary well equipment should have the same proprietary connection.

Ensure that proper running procedures are used. Check with the manufacturer on ways to distinguish between the two grades of 2. OD tubing. OD different grade tubing could not occur and to allow a slightly higher overpull value. If pressures are greater than 7, psi and the depth is greater than 13, ft, a pipe-body load analysis should be performed. In sour service for L80, C90, and T95, triaxial stress intensity should be checked and a design factor greater than 1.

Apache Tomcat software powers numerous large-scale, mission-critical web applications across a diverse range of industries and organizations. Some of these users and their stories are listed on the PoweredBy wiki page. The Apache Tomcat Project is proud to announce the release of version This release implements specifications that are part of the Jakarta EE 10 platform.

Applications that run on Tomcat 9 and earlier will not run on Tomcat 10 without changes. This conversion is performed using the Apache Tomcat migration tool for Jakarta EE tool which is also available as a separate download for off-line use.

Full details of these changes, and all the other changes, are available in the Tomcat The Apache Tomcat Project is proud to announce the release of version 9. This release implements specifications that are part of the Java EE 8 platform. The notable changes compared to 9. Full details of these changes, and all the other changes, are available in the Tomcat 9 changelog.

This release is a milestone release and is targeted at Jakarta EE This will almost certainly require code changes to enable applications to migrate from Tomcat 9 and earlier to Tomcat 10 and later.

A migration tool is under development to aid this process. Full details of these changes, and all the other changes, are available in the Tomcat 11 alpha changelog. The Apache Tomcat Project is proud to announce the release of version 8. This release implements specifications that are part of the Java EE 7 platform. The notable changes compared to 8.

Full details of these changes, and all the other changes, are available in the Tomcat 8 changelog. The Apache Tomcat Project is proud to announce the release of 1. This release contains a number of bug fixes and improvements compared to version 1. Full details of these changes, and all the other changes, are available in the changelog. The Apache Tomcat Project is proud to announce the release of version 2.

The notable changes compared to 2. Download ChangeLog for 2. This release implements specifications that are part of the Jakarta EE 9 platform. Full details of these changes, and all the other changes, are available in the Tomcat 10 changelog.

The Apache Tomcat Project is proud to announce the release of version 1. The notable changes since 1.