Summary Questions arise whether bottomhole pressures (BHPs), derived from their wellhead counterpart (WHP), lend themselves to transient analysis. That is because considerable heat exchange may affect the wellbore-density profile, thereby making the WHP translation a nontrivial exercise. In other words, gas density is dependent on both spatial locations in the wellbore and time during transient testing. Fully coupled wellbore/reservoir simulators are available to tackle this situation. However, they are not readily adaptable for their numeric formulations. This paper presents analytic expressions, derived from first principles, for computing time-dependent fluid temperature at any point in the wellbore during both drawdown and buildup testing. The simplicity of the analytic expressions for Tf (z, t) is profound in that one can compute flowing or shut-in BHPs on a spreadsheet. Two tests were considered to verify the new analytic formulae. In one case, measurements were available at both sandface and surface, and partial wellhead information was available in the other case. We explored a parametric study to assess whether a given wellbore/reservoir system will lend itself to wellhead measurements for valid transient analysis. Reservoir flow capacity (kh) turned out to be the most influential variable. Introduction Gas-well testing is sometimes conducted by measuring pressures at the wellhead. Both cost and circumstance (high pressure/high temperature, or HP/HT)often necessitate WHP monitoring or running the risk of having no tests at all. Methods for computing BHP from wellhead pressures for steady flow in gas wells are well established in the literature. For dry-gas wells, the widely used method of Cullender and Smith is most accurate, as confirmed by subsequent studies. For wet gas, either a two-phase model, such as the one offered by Govier and Fogarasi, or the modified Cullender-Smith approach appears satisfactory. However, these methods apply to steady-state gas flow and implicitly presuppose that the wellbore is in thermal equilibrium with the formation. These assumptions may be tested during a transient test. That is because unsteady-state wellbore heat transfer occurs even after the cessation of the wellbore-fluid-storage period. Steady-state fluid flow ordinarily implies the absence of wellbore effects from the viewpoint of transient testing. Consequently, one needs to develop working equations by conserving mass, momentum, and energy in the wellbore to capture physical phenomena. Earlier, we presented a forward model and showed its capability to reproduce BHP, WHP, and wellhead temperature (WHT) given reservoir and wellbore parameters. However, translation of WHP to BHP was not demonstrated clearly. The intent of this work is to present a framework for rigorous computation of BHP from WHP. To achieve this objective, we developed analytic expressions for depth- and time-dependent fluid temperature during both flow and shut-in tests. These temperature relations, in turn, allow computation of gas density and, therefore, pressure at any point in the wellbore.

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Core Ideas Soil water release curve is important but difficult to measure. HYPROP and WP4 are used to develop the soil water release curves for three soils. HYPROP and WP4 provided a good and simple way to measure soil water release curves. A soil water release curve (SWRC) describes the critical and soil‐specific relationship between soil water content and matric potential. In this study, soil moisture and corresponding matric potentials were measured using (1) a new method by HYPROP and WP4 dewpoint potentiometer, and, (2) the traditional method by hanging water column, Tempe cell, and pressure plate. The SWRCs were developed for Fargo silty clay, Glyndon silty loam, and Hecla sandy loam soils by using the van Genuchten model. The goodness of fit between the fitted SWRC and the measured data agreed well with R2 between 0.91 and 0.98. The comparison for the fitted SWRCs showed that the SWRCs for Hecla sandy loam soil provided the best agreement while Glyndon silty loam soil had the best match in terms of slope and shape. The SWRCs for Fargo silty clay soil did not provide a good match between the two methods. The difference in water content between the two fitted SWRCs was less than 2% for Glyndon silty loam and Hecla sandy loam soils. However, Fargo silty clay had a 4.5 to 5% difference for 66% of the measurements, possibly due to the different bulk densities caused by shrinkage and swelling nature of the clay soil. Since the best fitted van Genuchten parameters were within the reference range that was acceptable for the same type of soils, the HYPROP and WP4 can be used to develop SWRCs that are comparable to the traditional laboratory methods for the three soils in the Red River Valley.

Vacuum packaged beef strip-loins (fresh and aged) were repackaged on polystyrene trays and overwrapped with food grade cling film for the storage study. Several volatile compounds such as 3-methyl-1-butanol, 2,3-butanedione, 2-butanone, 3-hydroxy-2-butanone, acetic acid and a few hydrocarbons were detected in the headspace of these tray packaged fresh and aged beef strip loins both in the control and Salmonella typhimurium inoculated samples, in varying concentrations. These compounds were identified using manual headspace solid-phase microextraction (HS-SPME) in combination with gas chromatography/mass spectrometry (GC-MS) over a storage period of 4 days and samples were incubated at 20°C. No naturally occurring Salmonella was present in the control samples. Hexanal (r=0.99), carbon dioxide (r= 0.98), 3-hydroxy-2-butanone (r=0.93) and 2-methyl propane (r=0.95) showed positive correlations with Salmonella population for fresh beef samples. In aged beef samples, 3-methyl-1-butanol (r=0.99), 3-hydroxy-2-butanone (r= 0.98), carbon dioxide (r=0.98) and acetic acid (r=0.86) showed similar trends. In fresh beef samples, F values were significant at p<0.05 for 3-hydroxy-2-butanone and for Classification: Muscle FoodsElectronic supplementary material The online version of this article

Summary Flow-rate metering has a less-than-satisfactory track record in the industry. Modern sensors offer a solution to this vexing problem. This paper offers two methods for estimating flow rates, predominantly from temperature data to complement-rate measurements. One approach consists of modeling the entire wellbore and requires both wellhead pressure (WHP) and wellhead temperature (WHT), whereas the other uses transient temperature formulation at a single point in the wellbore to compute the total production rate. In the entire-wellbore approach, we use a wellbore model handling steady flow of fluids but unsteady-state heat transfer to estimate production rate, given wellhead pressure and temperature. The model rigorously accounts various thermal properties of the fluid and the formation, including Joule-Thompson (J-T) (Thompson and Joule 1853) heating and/or cooling. In the single-point approach, a single-point-temperature measurement made anywhere in the wellbore, including at the wellhead, is needed to estimate the mass rate at a given timestep. The method entails full transient treatment of the coupled fluid-and heat-flow problem at hand. Examples from both gas and oil wells are shown to illustrate the application of the proposed methodology. Good correspondence between the measured and calculated results demonstrates the robustness of the proposed methods. These methods provide important rate information in various settings. For instance, in mature assets they can fill in the information void between tests or replace suspect rate data. Even well-instrumented wells can benefit because the methods can act as a verification tool, particularly in assets where integrated asset models are used to fine tune rate allocation. In addition, the single-point approach can provide the much needed rate information during pressure-transient tests.