Based on what I understand from your question, it seems you are concerned with the compressibility in the wellbore. If I am not right, please let me know. In that case, yes, you need to take some margin for the compressibility based on the thermal transfer between the reservoir and the wellbore fluid. In the case of liquid, I doubt that the impact will be large. In the case of gas, the average of temperature at the surface and reservoir temperature should be sufficient. Good luck.

@Khaldoon Al-Obaidi : Thank you Sir for your reply. Your view regarding the thermal dependence of compressibility of the fluid in the well bore is very helpful.

However, my concern was little different. In producer wells, the hotter oil or gas flowing from the reservoir to the wellbore will have a temperature gradient in the wellbore. Further, the temperature will depend on the fluid flow rate. Research has been done to quantify this aspect for producer wells.I wanted to see if similar effects are present in injector wells. i.e: will the temperature at the sandface depend on the rate at which the injector fluid is injected into the reservoir.

Bhaskar, Absolutely, and of course this is true.  As a matter of fact, measurements can be made using temperature to identify fluid receipt zones, and this is part of normal production monitoring survey activity.  Obviously, this depends on the temperature differentials, and the lower the differential the lower the resolution. For injector wells it is pretty simple, as there is only one fluid state. For producers it is very different, as in the case of mixed fluid flows, particularly involving gas, you can imagine that the temperature behavior along the producing zones is complex.  Also, don't forget fluid flows behind casing - i.e. in places other than the production and injection zones.  These can also actually even be identified using temperature measurements.  So there is a lot that can be done with a simple thermometer in a well bore.

My bad. What Harald said is the answer for your question. Your problem will be the calibration of temperature to flow rate. Plt and calibration curve should do the trick. Good luck. 

 Bhaskar, 

The thermodynamic behavior of organic and inorganic compounds present in the fluids produced are affected by temperature. For example, the solubility of the paraffins in crude strongly temperature dependent; the stability of carbonates and sulphates contained in the formation water temperature dependent. The behavior of the clay minerals is a function of temperature.

Regards,

Bhaskar

From a heat transfer point of view the three(3) mechanisms (convection......) are the ones driving the process therefore the change in temperature. The answer is yes they would and once you establish a stable system under injection then the "system" (well, near wellbore, casing, cement...) will have different conditions to those when the well is shut-in.  If you take the changes of stresses as a function of temperature as an example then you can see that Young modulus, Heat transfer coefficient and Poisson's ratio will change resulting in different fracture pressures. Most of these mechanical properties are closely linked to the parameters that you mentioned (skin, permeability...) as the way the heat is transferred from the reservoir to the fluid will changes. I attach a publication that I hope helps with your question

Many phenomenon can determine a relationship between 1D in-well temperature profile and  3D reservoir properties / sand-face properties. Most often only a few of those will actually have a significant effect. Some examples (not exhaustive): Joule Thomson effect during gas decompression in a gas producer / high permeability reservoir, reservoir fracturation in a water injector / low permeability reservoir, steam breakthrough in a SAGD producer, hydrate or asphaltene deposition, etc. The effect can be counter current to flow (as in the Joule Thomson case) or co-current (as in the fracturation case). They can be repeatable (Joule Thomson) or hysteretic (fracturation case) an can be very fast (significant for interpreting a DST lasting a few hours) or slow (detectable over years). Do not hesitate to provide more details of the specific context you are interested in.

@Harald Bolt: Respected Sir, thank you for the answer. Your answer matched my contention that we can measure the layer wise injection rates (in multi layer reservoir), based on the measured temperature. Some other people had told me the other way, and hence I wanted to confirm on researchgate.

Sir, do you know of any quantitative model that would describe the injection flow rate into a layer, based on the temperature in the well-bore measured near the layer at which injection is happening? 

I still have some doubt regarding this. When the cold injector fluid reaches a temperature gauge just above the injected layer, the temperature detected will only be the steady temperature of the cold water front, and it will not have any bearing on the flow rate of the injection into the reservoir.

And of course, as you said, there will be a lot of temperature interactions behind the casing. Modelling behind casing effects will be a complicated problem, but right now I am trying to model the simplest ideal case.

Thanking you.

@Juan Tovar: Respected Sir, Thank you for the answer and clarifying my doubt. I am looking to work in the area of thermal effects in injectors, and this answers me a lot. Further, the paper you sent me on thermal induced fractures was an eye opener, as I missed out on this thermal effect. It is something that I should try to incorporate in my studies.

Thank you again.

@Jairo ANTONIO Sepulveda Gaona: Respected Sir, Thanks a lot for your answer.

@Pierre Bergey: Respected Sir, Thanks a lot for the very in depth reply. Sir, if you could please, can you please elaborate on the slow thermal effects in the reservoirs? I only thought that the thermal effects due to reservoir production or injection are only observable in early times.

Thanking you.

Bhaskar, There is a fairly good discussion on temperature logging and interpretation -  including discussion of a number of the issues you are raising - in "Cased-Hole Log Analysis and Reservoir Performance Monitoring" by R. Bateman. The book is dated - true - but the information is absolutely correct and easy to understand.