Published by the DTI Oil & Gas Directorate for the reservoir engineering and IOR community in the UK.
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Reservoir Fluid Studies

Professor Ali Danesh (ali.danesh@pet.hw.ac.uk) outlines the current research programme in the PVT and Phase Behaviour Laboratory in the Institute of Petroleum Engineering at Heriot-Watt University.

The PVT and Phase Behaviour Laboratory in the Department of Petroleum Engineering at Heriot-Watt University has targeted its effort over two decades towards the measurement and modelling of properties and behaviour of reservoir fluids.  The capabilities developed within the research group will be targeted towards related areas of importance to the recovery of hydrocarbon reservoir fluids, over the next phase of the project beginning in November 2002 for three years. The research areas will include reservoir fluid sampling, high-pressure-high-temperature (HPHT) fluids, partitioning of gas tracers and asphaltene deposition.

Fluid Sampling:
Reliable sampling is the most important element of any reservoir fluid analysis, yet major challenges are still hampering its efficient and low cost operation.  The problems associated with collection of unrepresentative samples, in particular samples contaminated with oil based mud filtrate, will be studied in this programme.  Recent results generated in this laboratory have indicated that an oil sample contaminated with mud filtrate could be analysed and tested almost as reliably as that of the original uncontaminated oil.  The current emphasis is on gas condensate systems, where components of reservoir fluids may be lost to the invading mud filtrate.  The above problem is tackled by using tracers in the drilling mud filtrate.  The developed method will be also applied to bottom hole samples impaired by phase change during sampling.

Figure 1 compares the condensate drop-out of a collected gas sample, contaminated with mud filtrate and partially depleted during sampling with that of the original gas condensate sample.  Note that the collected sample is totally unrepresentative.  However, applying the developed tracer method to retrieve the original composition has resulted in reliable estimation of the fluid behaviour.  

Figure 1.  Condensate volume fraction in constant composition expansion test at 100^oC.

Partitioning of Gas Tracers:
Well to well gas tracer tests are becoming a practical and valuable tool in detection of the injected gas route within the reservoir, particularly in identifying fractures, attics, sealing faults, and in estimation of the displacement efficiency.  Information on partitioning of tracers between gas and oil is required in the tracer analysis.  Studies of tracers for their application in the mud filtrate contamination detection, indicated that their partitioning behaviour was quite different from that of hydrocarbon systems.  These compounds, which could be liquid at surface conditions would become volatile even more than methane at reservoir conditions.  The existing experimental facilities are used to generate the required data on these compounds for developing a methodology to predict their partitioning behaviour for field application.

High Pressure-High Temperature (HPHT) Fluids:
The volatility of heavy compounds increases with increase in pressure and temperature.  This may result in gas condensate fluids that are highly rich in heavy compounds.  Furthermore, water volatility also increases sharply with temperature, hence, water can become a major constituent of a HPHT fluid.  It is common to neglect the effect of water on the phase behaviour of hydrocarbon systems, which may be adequate for reservoirs at moderate pressure/temperature.  However, the concentration of water in HPHT gas reservoirs could be quite significant affecting the fluid behaviour considerably. 

The HPHT experimental set-up in this laboratory, with the upper temperature and pressure limits of 200^oC and 200 MPa (30,000 psi) respectively, provides viscosity, interfacial tension and PVT data on reservoir hydrocarbons with water present.  The generated experimental data is used to improve/develop fluid models for field application.  Water also affects hydrocarbon physical properties, such as viscosity and interfacial tension.  Figure 2 compares measured viscosity of a model volatile oil at a temperature of 200^oC and at pressures above the bubble point, without water and with 5.40 mole% of dissolved water.  Note an increase of over 20% in viscosity due to dissolved water.  

 
Figure 2.  Measured Viscosities Versus Pressure of Volatile Oil With and Without Water at 200°C.

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