(83a) Iron Sulphide Scale Prediction in Oil Wells

Water flooded oil fields are likely to experience biogenic reservoir souring (in situ H₂S formation) which is the main cause of iron sulphide (FeS) scale problems in this type of production systems.

Despite the increased number of fields around the world affected by this flow assurance problem, the current techniques used for FeS prediction are inaccurate and may lead to inconclusive and misleading results. In fact, FeS scale precipitation depends on in-situ pH, dissolved H₂S, CO₂ and iron concentration which are difficult or in some circumstance impossible to obtain from field samples due to limitations in the sampling and analysis methods.

To overcome this challenge, we have developed a workflow which combines the use of Pressure/Volume/Temperature (PVT) software with Vapour/Liquid Equilibrium (VLE) and scale prediction calculations to model three phase flow rate changes, three phase H₂S and CO₂ compositional changes and pH trends from the reservoir to the first stage of separation using the limited field data available. This information is then used as input for the scale prediction model to provide more reliable scale prediction trends and identify areas in the well with a high scaling risk. When applied to medium/heavy oil wells, there are additional iterative steps required to obtain the three phase H₂S and CO₂ concentrations because we must use a so-called â??Black Oilâ? PVT model which does not accurately account for gas/oil H₂S and CO₂ partitioning.

We applied this new workflow to two different water flooded North Sea oil fields and here we show our results for a representative Well A. This well produces 38°API oil, contains high CO₂ (5% in the gas phase at separator conditions) and low H₂S (500ppmv at the same conditions) but shows FeS precipitation in the produced fluids.  

The first step of our workflow is to tune the oil and gas Equation of State (EOS) in the PVT model to obtain the correct GOR and densities. Using this information we can calculate the gas breakout point and understand how the three phase relative volumes change along the well.

Knowing the separator temperature, pressure, gas H₂S and CO₂ mole fraction we can adjust the hydrocarbon composition to obtain the correct concentrations in the gas phase using flash calculations in the PVT model. This will also give us the hydrocarbon H₂S and CO₂ content. Finally, with vapour/liquid equilibrium equations we calculate the water phase H₂S and CO₂ concentration in the separator and using the correct flow rates we determine the total mass of H₂S and CO₂ in the system.

Total H₂S and CO₂ are all recombined to a two phase system in the reservoir where we fix the oil/water partitioning coefficient (form literature values) and calculate the oil and water H₂S and CO₂ concentrations.

When the fluids are taken into the wellbore, the same process is repeated for the two phase system up to the point of gas breakout.

At gas breakout, we run an iterative process to calculate the final H₂S and CO₂ concentration in all three phases which satisfies the mass balance, vapour/liquid equilibrium equation and the fixed oil/water partitioning coefficient. These results give us an H₂S and CO₂ concentration trend from the reservoir to the first stage of separation.

To model the water pH we start from the reservoir using the given water composition, the calculated dissolved H₂S and CO₂ and the carbonate equilibrium (CaCO₃ saturation ratio, SR =1) which applies to reservoirs containing carbonate rock.

In the wellbore we take this produced water composition but change temperature, pressure, H₂S and CO₂ to reflect the values associated to each selected point in the well.

Finally, we use the calculated H₂S, CO₂ and pH as data input for the scale prediction model to obtain iron sulphide scaling trends.

The results we obtained show a rather constant pH trend along the well up to the point of gas break out. Due to the high CO₂ concentration, the pH in this region is kept below 6 and the iron sulphide scaling potential slightly decreases as we go up the well thanks to the temperature changes (less precipitation at lower temperature).

However, at gas breakout CO₂ is released and the pH increases causing an increase in iron sulphide scaling potential (which is higher at higher pH).

The pH, bicarbonate and the expected dissolved iron values obtained from our modelling calculations are comparable to field readings and the discrepancies can be explained by the limitations of sampling and analysis techniques as well as uncertainties associated with H₂S solubility in oil and water at low concentrations.

The scaling potential does not change significantly along the well and is limited by the amount of iron available. This information can be used to deploy an effective prevention or mitigation strategy for the control of FeS. The pH values and dissolved H₂S and CO₂ can also be used to run in-situ corrosion calculations and identify areas at higher risk.

Additional challenges associated with FeS scale predictions remain (i.e. prediction of different iron sulphide crystal forms) but this work overcomes the significant implications of pH effect on FeS precipitation.

Applying this newly developed workflow allows any user with access to commercially available PVT and scale prediction tools to answer critical questions related to FeS scaling potential in oil fields which cannot be answered by using these tools individually. This information ultimately allows an operator to deploy effective and efficient mitigation strategies tailored to the sulphide scaling problem.