T2=Ts+(T1-Ts)exp(-UA) is one commonly used equation.
T2 is outlet temperature, Ts is surrounding temperature, T1 is inlet temperature, U is the overall heat transfer coefficient.
A is the relaxation distance which is a function of mass flow rate, area of pipe, heat capacity and overall heat transfer coefficient.
How would the heat capacity be used for a natural gas composed of C1 to C6? Would Cp or Cv value be used for a natural gas pipeline?
How would these values be taken into consideration when phase changes occur (occurring both as liquid and gaseous phases) and at what temperature would the heat capacity values be used at?
You can use my hydrate prediction software, HYD-PREDIC, showcased on www.eq-comp.com for finding out temperature profile of a multiphase vertical pipeline. It gives temperature profiles and profiles of other properties of crude oil besides predicting hydrate formation. The link to the website and one sample result file is attached.
www.eq-comp.com/hyd-predic-hydrate-prediction-flow-assurance-software
We are doing Temp Simulation using THERMOSIM, TGT's propriety advance mathematics software, in the field in vertical and horizontal wells, but we have not done it for normal pipelines. I checked this point with the software developer and R&D Team Leader, and he thinks it can be done equally effectively in pipelines. It is well beyond a simple equation though. The field results - from wells - are superb, and spot on in history match.
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