Long sweep stb vs std-Common Commands SCPI

Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. Characterizing, measuring, and correlating the physical properties of natural gases must take into account this variety of constituents. This article discusses phase behavior, pressure volume temperature PVT behavior, gas density and formation volume factor FVF , viscosity, determining reservoir fluid properties, retrograde behavior, and equations of state EOS. A dry-gas reservoir is defined as producing a single composition of gas that is constant in the reservoir, wellbore, and lease-separation equipment throughout the life of a field.

Long sweep stb vs std

Long sweep stb vs std

Long sweep stb vs std

Long sweep stb vs std

Long sweep stb vs std

Bareback black fucking determination of gas viscosities has low economic value. See Understanding Command Synchronization. I never realized that there were so many things to take into account before bending a pipe like having a short radius or long radius elbows. The density of a gas can be calculated from the real-gas law once a z factor has been determined. Studies of retrograde-condensate gas reservoirs must Long sweep stb vs std changes in condensate yield as reservoir pressure declines, the potential for decreased well deliverability as liquid saturations increase near the wellbore, and the effects of two-phase flow Long sweep stb vs std wellbore hydraulics. Prohibits the instrument from executing any new commands until all pending overlapped commands have been completed.

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Can you tell me how I can fix the problem of the standardized output not including the full information? Featured on Meta. Nawaz: "Unsafe" is a bit hyperbolic. Etb toilets back to back, dropping into a santee on it's back. Visit chat. No, not if there are x's in the Charlie rocket pants. Long sweep stb vs std thanks. I'm confused as to which standardized estimate to report for a path in a syd equation model with several latent and observed variables including 1 binary observed variable b1regimen. Add Your Message Here. Viewed 32k times.

In our previous article Pipes and Bends —Part 1 we discussed about the difference between a pipe and a tube, meaning of nominal diameter and schedule of a pipe.

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In our previous article Pipes and Bends —Part 1 we discussed about the difference between a pipe and a tube, meaning of nominal diameter and schedule of a pipe. In this article we will discuss bends, elbows and miter bends. There is always a doubt about the terms bends and elbows on ships. They are frequently used as synonyms.

The difference between them is as follows:. Elbows are again classified as long radius or short radius elbows. The difference between them is the length and curvature. A short radius elbow will be giving the piping a sharper turn than a long radius elbow.

Credit: Wikimedia- 90 degree long radius elbow. Another type of bend is a Miter bend. A Miter bend is a bend which is made by cutting pipe ends at an angle and joining the pipe ends. A true miter bend is a 90 degree bend made by cutting two pipes at 45 degrees and joining them by welding. Similarly three pipes cut at He has 12 years of experience as Marine Engineer.

May I use your articles to teach my Marine Engineer class? Our school is San Jacinto Maritime College. You can see me under Faculty. I would like to put this material in our text book for Pumpman.

Thanks, USA I also love that article. I never realized that there were so many things to take into account before bending a pipe like having a short radius or long radius elbows. I never realized that bending is better for flow than welding is.

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Comments thank u… it was a useful information. Best Regards, Jason Ho. Leave a Reply Cancel reply Your email address will not be published. We use cookies to ensure that we give you the best experience on our website. If you continue to use this site we will assume that you are happy with it.

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Long sweep stb vs std

Long sweep stb vs std. Your Answer

Episode of the Stack Overflow podcast is here. We talk Tilde Club and mechanical keyboards. Listen now. Asked 7 years, 2 months ago. Active 7 years, 2 months ago. Viewed 32k times. I have a variable: string item; It gets initialized at run-time. Ivan Kruglov Ivan Kruglov 3 3 silver badges 12 12 bronze badges.

I guess we have different ideas what it means for something to be "unsafe". This is just quirky behavior which in a lot of situations is even preferred. Obviously atol is about levels away from being a great answer, but "unsafe" seems like an exaggeration. It is unsafe because it doesn't tell you the between these two calls : atoi "0" and atoi "abc". Both return 0. Nawaz: "Unsafe" is a bit hyperbolic. It doesn't allow you to check whether the input really was a numerical string; whether or not that's "safe" depends on where it comes from and what you're doing with it.

For the record calls to atol result in undefined behavior if an error occurred. Nawaz this is why I check to make sure my string is a valid number before I do anything like these top to examples. But is it still "Unsafe" if I do this? Use a string stream.

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A job two weeks ago. Two toilets back to back, dropping into a santee on it's back. The santee is the same as a medium bend. Instead of all of the waste poo going downstream of the fitting, quite a bit went the other direction, plugging up a 1.

A wye, or long 90 would have forced the water downstream. You will lose speed with that fitting. I can't see it from where I live. I've always plumbed for best performance. I like my cars that way too. Terry , Jun 10, You must log in or sign up to reply here. Show Ignored Content. Similar Threads: short sweep. Share This Page Tweet.

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Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. Characterizing, measuring, and correlating the physical properties of natural gases must take into account this variety of constituents.

This article discusses phase behavior, pressure volume temperature PVT behavior, gas density and formation volume factor FVF , viscosity, determining reservoir fluid properties, retrograde behavior, and equations of state EOS.

A dry-gas reservoir is defined as producing a single composition of gas that is constant in the reservoir, wellbore, and lease-separation equipment throughout the life of a field. Some liquids may be recovered by processing in a gas plant. A wet-gas reservoir is defined as producing a single gas composition to the producing well perforations throughout its life.

Condensate will form either while flowing to the surface or in lease-separation equipment. A retrograde-condensate gas reservoir initially contains a single-phase fluid, which changes to two phases condensate and gas in the reservoir when the reservoir pressure decreases.

Additional condensate forms with changes in pressure and temperature in the tubing and during lease separation. From a reservoir standpoint, dry and wet gas can be treated similarly in terms of producing characteristics, pressure behavior, and recovery potential. Wellbore hydraulics may be different. Studies of retrograde-condensate gas reservoirs must consider changes in condensate yield as reservoir pressure declines, the potential for decreased well deliverability as liquid saturations increase near the wellbore, and the effects of two-phase flow on wellbore hydraulics.

McCain Jr. Copyright Pennwell Books, A retrograde-condensate fluid has a phase envelope such that reservoir temperature lies between the critical temperature and the cricondentherm Fig. As a result, a liquid phase will form in the reservoir as pressure declines, and the amount and gravity of produced liquids will change with time. The primary difficulties in producing condensate reservoirs are as follows:.

In a wet-gas reservoir, temperature is higher than the cricondentherm Fig. Therefore, a liquid phase never forms in the reservoir. Considerable liquid can still form condense at surface conditions or even in the wellbore. The term "condensate" is often applied to any light hydrocarbon liquid produced from a gas well. However, the term "condensate reservoir" should be applied only to situations in which condensate is actually formed in the reservoir because of retrograde behavior.

Wet-gas reservoirs can always be treated as containing single-phase gas in the reservoir, while retrograde-condensate reservoirs may not. In a dry-gas reservoir, the cricondentherm is much lower than the reservoir temperature Fig. While the difference between retrograde-condensate and wet gases is notable, there is much less distinction between wet and dry gases. For both wet and dry gases, reservoir engineering calculations are based on a single-phase reservoir gas.

The only issue is whether there is a sufficient volume of produced liquid to be considered in such calculations as material balance or wellbore hydraulics. Therefore, atmospheric pressure must be added to gauge pressures to convert them to an absolute basis. For precise scientific and engineering applications, actual atmospheric pressure i.

Standard temperature and pressure are set by different governmental agencies and should be determined for a specific field or reservoir to be sure that reserves and produced quantities are reported with the correct bases. Application of Eq. Such determinations would include apparent molecular weight and z using pseudoreduced pressure and temperature and corrections for nonhydrocarbon components.

The density of a gas can be calculated from the real-gas law once a z factor has been determined. The gas formation volume factor is defined as the volume occupied by a gas at reservoir conditions divided by the volume at standard conditions:. The second and third lines of Eq. Accurate determination of gas viscosities has low economic value. Instead, values are normally determined from one of two correlations. The first one in common use today, from Lee et al.

The gas density in Eq. The equivalent formula for SI units pressure and temperature in kPa and K, respectively is. Another common correlation [3] entails a two-step graphical process and is cumbersome for computer applications.

Because gas viscosities are seldom needed with great accuracy, the Lee et al. Condensation of liquids from wet-gas and retrograde-condensate fluids in the production system means that gas produced from separation equipment may be significantly different from the gas that flows into the wellbore from the reservoir. In general, separator gas will be lower in gravity and will have fewer high-molecular-weight hydrocarbons present in the mixture.

For proper laboratory measurements, a bottomhole sample should be collected. An alternative is a reconstituted sample that is created by mixing the separator-produced gas and liquid in proportion to their relative production rates.

When the compositions of liquid and gaseous streams have both been measured, the composition of the mixture can be determined from. Relative molar amounts can be determined by converting measured produced volumes either to moles or to equivalent standard cubic feet.

For a gas phase, conversion of a produced volume referenced to standard conditions to moles is. If liquid volume is measured at standard conditions, density can be calculated from specific gravity or API gravity. If liquid molecular weight is not measured, it can be approximated with the Gold et al.

An alternative to converting measured volumes to moles is to convert all measured volumes to equivalent standard volumes because standard volume is directly proportional to moles through the value of the standard molar volume.

Liquid volumes are converted to equivalent gas standard volumes using a parameter called the gas equivalent of oil. This parameter represents the effective standard volume occupied by hydrocarbons that are liquid at surface conditions but are in the gas phase at downhole conditions. This parameter is calculated by. Liquid-production volumes are multiplied by GE o to determine the equivalent standard volume as gas in the reservoir; that is,. These equations also can be used to determine the equivalent gas production of pure hydrocarbons separated from gas in a processing plant.

When wellstream composition is unavailable, correlations must be used to determine gas properties, requiring the calculation of the wellstream mixture gravity on the basis of the gravity of the separator gas often called dry gas and the specific gravity of the produced liquid condensate or oil :.

Y is the produced condensate yield. When a liquid phase begins to form in the reservoir, the produced stream is no longer representative of the reservoir-fluid composition, but rather only the composition of the fluids entering the wellbore. Laboratory measurements of the PVT behavior of condensate systems are similar to tests used for black oils; however, the primary interest becomes the measurement of relatively small amounts of condensed liquid.

Two types of tests are generally run on retrograde fluids: constant-composition expansion CCE and constant-volume depletion.

For examples refer to Tables 1 through 3. Table 1 - Example field and analysis data for retrograde-fluid study. Table 2 - Example volumetric behavior of condensate well fluid. Table 1 [6] gives the compositions of separator gas and liquid streams and other data used in making a recombined sample for analysis of reservoir-fluid composition.

A CCE using a visual cell furnishes the dewpoint of the reservoir fluid at reservoir temperature and the total volume of the reservoir fluid as a function of pressure. The volume of liquid formed at pressures below the dewpoint can also be measured. The term "relative volume" refers to the volume of gas plus liquid compared to the dewpoint volume.

Retrograde-liquid volume is given as a percent of pore space, which essentially shows how the average condensate saturation changes with average reservoir pressure. Visual cells also can be used to simulate pressure depletion.

The validity of these tests is based on the assumption that the retrograde liquid that condenses in the reservoir will not be mobile.

Table 3 is an example of a visual-cell depletion study on the same retrograde gas for which properties are shown in Tables 1 and 2. The depletion study begins by expanding the reservoir fluid in the cell until the first depletion pressure is reached 5, psig in this example.

The fluid in the cell is brought to equilibrium, and the volume of retrograde liquid is observed. Gas is removed from the top of the cell while a constant pressure is maintained until the hydrocarbon volume of the cell is the same as when the test began.

The gas volume removed is measured at the depletion pressure and reservoir temperature, analyzed for composition, and measured at atmospheric pressure and temperature. The ideal-gas law can be used to calculate the "ideal volume" at the depletion pressure and reservoir temperature of the gas withdrawn from the cell.

Dividing the ideal volume by the actual volume yields the deviation factor, z , for the produced gas. This is listed in Table 4 under z for the equilibrium gas.

The actual volume of gas remaining in the cell at this point is the gas originally in the cell at the dewpoint pressure minus the gas produced at the first depletion level. Dividing the actual volume remaining in the cell into the calculated ideal volume remaining in the cell at this first depletion pressure yields the two-phase deviation factor shown.

The two-phase z factor is an equivalent z factor that includes the total volume of gas plus liquid:. A series of expansions and constant-pressure displacements is repeated at each depletion pressure until an arbitrary abandonment pressure is reached. The abandonment pressure is considered arbitrary because no engineering or economic calculations have been made to determine this pressure for the purpose of the reservoir-fluid study. At the final depletion pressure, the compositions of both the produced well stream and the retrograde liquid are measured.

These data are included as a control composition in the event that the study is used for compositional material-balance purposes. In this case, initial condensate content was The gas formation volume factor was determined to be 0. These calculations indicate the large amount of liquid remaining in the reservoir at depletion even with excellent drainage to the wells.

Further reductions in recovery would be expected because of areas of the reservoir inadequately drained with existing wells.

These simulators are based on EOSs that describe the phase volumes and compositions of liquid and gaseous phases as functions of pressure and temperature. Because hydrocarbon molecules interact with each other in solution, the coefficients in an EOS are not always adequately known. Once this tuning process is complete, those coefficients can then be used to make predictions under differing operating conditions with some degree of reliability.

When the effects of complex phase behavior on phase compositions and physical properties cannot be calculated accurately with simple approaches, it is often desirable to use an equation of state EOS. An EOS approach is often necessary when dealing with volatile oils and retrograde-condensate gases. EOSs provide a numerical method for calculating both composition and relative amount for each phase present in the system. In reservoir simulation, EOS calculations are typically restricted to two hydrocarbon phases: a liquid oleic phase and a gaseous phase.

Long sweep stb vs std

Long sweep stb vs std