When preparing a blowout simulation, you will need to decide on the appropriate models for your simulation as well as setting the simulation options. (PVT model, multiphase flow model, oil viscosity model, gas viscosity model). This is done under Simulation Settings. Below is a description of the different models, and for which situations they are appropriate to be used.
|Vasquez-Beggs||Light oils, Medium oils||The Vasquez-Beggs correlation was developed using laboratory results from more than 600 crude oil systems, and measured over wide ranges of pressure, temperature, oil gravity and gas gravity. The reported error for solution GOR and oil formation volume factor were -0.7% and 4.7%, respectively.|
|Standing||Light oils, medium oils||50 experimentally determined data points on 22 different oil-gas mixtures from California were used in the development of the correlations.|
|De Ghetto||Light, medium, heavy and extra heavy oils||The De Ghetto model is a model especially optimized for heavy and extra heavy oils, although it may also be used for lighter oils. The model implements modified correlations of Standing and Vasquez-Beggs for heavy oils, and uses the standard correlations for all other oils.|
Oil or Oil & Gas
|The Hagedorn and Brown method was developed by obtaining experimental pressure drop and flow rate data from a 1500 ft deep instrumental well. Pressures were measured for flow in tubing sizes ranging from 1 ¼” to 2 ⅞” in O.D. A wide range of liquid rates and gas/liquid ratios were included, and the effects of liquid viscosity were studied by using water and oil as the liquid phase. The oils used had viscosities at stock tank conditions of 10, 35 and 110 cP. The Hagedorn and Brown method has been found to give good results over a wide range of well conditions and is one of the most widely used well flow correlations in the industry. The Hagedorn and Brown Correlation gives best results for wellbore with low to moderate liquid volume fractions (high GOR) and relatively high mixture velocities (annular-mist or froth flow).|
|Beggs & Brill||Horizontal well|
Oil or Oil & Gas
|The Beggs & Brill model is developed for tubing strings in inclined wells and pipelines for hilly terrain. This model results from experiments using air and water as test fluids over a wide range of parameters given below:|
gas flow rate 0-8.5 MScm/d
liquid flow rate 0-163.5 Scm/d
average system pressure 2-6.5 bar
pipe diameter 1-1.5 in
liquid holdup 0-0.87
pressure gradient 0-0.18 bar/m
incl angle -90 to +90 degrees also horizontal flow patterns
The correlation is known to overpredict pressure losses in large tubings and for large GOR (especially large for GOR > 890)
Oil or Oil & Gas
|For oil gravity less than 30° API. Most applicable for wellbores with GOR up to 5000.|
Gas, Gas & Condensate
|The Gray correlation is one of the most commonly used methods for gas-condensate well pressure profile prediction. The correlation notes that caution shold be used for the following conditions:|
flow velocities < 15 m/s
tubing sizes < 3.5 in
* roughness height < 8.44 m
|Gray Modified||Vertical wells|
|Modified version of the Gray model.|
|Duns & Ros||Vertical flow of gas and liquid mixtures in wells||Perform well for wells with high gas-liquid ratios (usually in mist flow regime) and condensate wells|
Oil gravity 13-65 API
Most applicable for wellbores with GOR up to 5000
|Vasquez & Beggs correlation from 1978 was based on a large data base, and is therefore applicable to a wide range of oils. An average error of -7.54% was reported.|
|This model, often referred to as either Beal or Standing, was developed by Beal and fitted by Standing. It is valid for Oil gravity: 15-53°API and Reservoir temperature of 100-229°F.|
|Egbogah||Light, Medium & Heavy oils||Based on the work of Beggs & Robinson, Egbogah & Ng proposed a new empirical viscosity correlation for heavy oils. The model range is Oil gravity: 5-58°API and Reservoir temperature, T: 15-80°C.|
|De Ghetto||Light, Medium, Heavy & Extra Heavy oils||The De Getto model is a modified correlation of Egbogah & Ng. The model handles both extra-heavy oil (°API <= 10) and heavy oil (10 < °API <= 22.3). For saturated and undersaturated oil viscosity prediction, the average absolute errors were reported to be 12% and 6%, respectively.|
|Lee||The model is applicable within a range of reservoir temperatures, T: 100-340 °F and pressures 100-8000 psi. Average reported error is 2-4%. For high gas viscosities the model is known to under-predict the viscosity.|
|Lee Modified||The modified Lee model is reported to have an average absolute error of 2.29%. Primary difference is that Lee modified performs better for a greater range of gas viscosities.|
Number of simulations (Monte Carlo iterations) – this value can be decreased to a low number in order to check if the blowout simulation is valid.
- If the blowout rates are zero after running a simulation with few iterations, the wrong PVT, Multiphase flow or oil viscosity model have been picked. Try to change model according to the descriptions above.
- The number of iterations should be left at 10000 when running a full simulation. If you increase the number, the simulation time will increase significantly.
- All other values should (normally) be left as is.