This paper will briefly discuss the laboratory measurements of PVT data. Each of the five PVT test performed on oil will be identified and the corresponding report formats explained. The two most commonly used data, formation volume factor and solution gas-oil ratio are generally not usable in their original forms for common reservoir applications. The paper will explain why and how to adjust them.
The application of PVT data will be investigated by the use of two case studies, both using the same PVT report. The case studies will show:
which PVTdata to use in material balance equations.
how PVT data in the form of flash testing may predict optimum separator conditions.
The phase behavior of a hydrocarbon reservoir is a dynamic event that is controlled by pressure, temperature and composition. To effectively manage the production of a hydrocarbon system that changes as it is being depleted. It is essential to be able to predict the physical properties of the reservoir fluid that will exist and govern that production process. Some of the predictive techniques available to the reservoir engineer are used for:
prediction or original oil in place
material balance - voidage calculations optimization of gas-oil separation reservoir fluid flow
fluid properties for financial and governmental requirements
The reliability of any predictive techn1que may be significantly enhanced by the collection of a representative sample of reservoir fluid with subsequent laboratory testing.
The cause of fluid flow during production is the pressure differential between the lower pressure in the well bore and the higher pressure area some distance into the reservoir. The pressure differential may be referred to as drawdown and is affected by the following:
flow rates;
Rock propertiesi
Fluid properties; and
Production history.
Single phase, unaltered reservoir fluid present in the well bore at reservoir depth is the objective during the procurement of samples for a PVT study. Drawdown, however, may cause the release and separation of gas from its associated liquid. The gas will stay in the reservoir until the evolved gas forms a continuous phase throughout the pressure affected area, after which the gas will flow to the wellbore. The gas saturation at which gas first becomes mobile is called critical gas saturation. In either case, the fluid produced would not be representative of the true reservoir fluid composition. This is evident when observing the producing gas-oil ratio when drawdown occurs, it is low before establishment of critical gas saturation and high during free gas flow relative to the true reservoir solution gas-oil ratio.
The one factor affecting drawdown that the reservoir engineer has control of is flow rate. Flow rate can be reduced until reservoir fluid alteration is minimized or eliminated and any previously altered fluid is removed from the sampling area. This process is called well conditioning. Gas-oil ratios of produced fluids are generally effective and convenient indicators of the progress of the conditioning program.
