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Scale Prediction in HPHT gas fields

By Bhagwan Bansal posted 06-04-2013 08:39 AM

  
Hi All

I am working on scaling potential in a HPHT gas field. Reservoir pressure is around 1000 bars and temperature is 180 deg C. We are expecting halites when producing with low water rate, other normal scales and sulphides continuously when producing water with gas.

We have water samples collected from a well below free water level in reservoir. We have PVT for gas also. We want to use scalechem for the scale prediction.

Can anybody advise on following aspects:
  1. Which version of scalechem to use relaibly - OLI studio 9.07 or older version which has been varified by E&P companies?
  2. How to saturate the well fluids at reservoir level?
    1. By reconcilining water and gas at sampling pressures or measurement pressure and then combining them at reservoir pressure and temperature in saturator mode using SR for CaCO3=1?
    2. By reconcilining the water and gas seperately at reservoir pressure and temperature?
  3. How we can tweak the model to predict the halites
  4. Since sulphides  solubility is highly dependent upon pH of reservoir saturated gas and water combine, how to varify that we have predicted pH of reservoir condition saturated fluids correctly. 

Any comment is welcome on scaling prediction in HPHT gas well.

Thanks to all readers

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Comments

Jack Lynn
07-04-2013 01:42 AM

What kind of water samples did you get, and how were they processed? This is the most critical aspect of modeling any scaling scenario, and it’s the one area that I see most operators fail to get what they need, usually because of cost. In the long run, (I have 38 years of experience that prove this to be true statement) this is a false economy, and your ability to model scaling tendencies will suffer if you don’t get appropriate water samples.
I always suggest for any one doing this type of work that they obtain mono-phasic bottom-hole samples; and get full geo chemical analysis including partitioned gases (CO2, H2S) in the fluids.
The samples should be prepared for testing in a PVT lab set up. The tests and programs that need to be run on the sample are:
1) Psat (bubble point of the gas in the water)
2) Total GWR (gas water ratio)
3) Differential gas liberation from the brine at least four pressures
4) C7+ GC analysis on all gas phases
5) After the PVT studies, then start to flash the reaming water samples off, and collect your samples for water analysis
6) First 20 cm³ flashed off—measure pH as soon as possible (as the flash is completed)
7) Take one sample, about 20 mls of flashed water, flashed directly into 10 % nitric acid, for iron content (critical if you have H2S issues)
8) Flash the remaining water into a glass bottle, seal, and send for complete geochemical analysis
From this data you have all of the appropriate information you need for modeling – especially gas saturation, and concentrations (the true partitioned values), from the reservoir, at different depths and at the surface, hence you can model changes in scale tendency from well bore to surface.
As for the geochemical models all are relatively useful, and I find more problems with correct input then calculations. The one issue that I would caution you about is the fact that ALL geochemical models are STOICHIOMETRIC in nature. This means they are as good as the Ksp data that goes into them.
However be aware that a certain group of iron sulfides, the pyrrhotites, can be non-stoichiometric in nature, and the models fail with this material, since Ksp is a function of composition, and these pyrrhotites do not all have a constant composition. Typical minerals like pyrite, marcasite, etc, can be modeled very well, but the pyrrhotites are another story (we’ve worked on them here in Saudi for several years now, and are in fact woefully familiar with the little beggars). And from a stimulation/scale control point of view there are differences in stimulation approaches when dealing with different species of iron sulfide.
Also be aware that if you see iron sulfides, then you have a source of iron --- is it corrosion? Is it from the formation (rock or water)? is it form drilling and completion fluids, stimulation fluids? Many issues too many to cover in short discussion
Cheers, and good luck ---And don’t let management talk you out of a good down-hole sample – it will be well worth their while, in terms of accurate, and dependable results.