1D Asphaltene Deposition Simulator for Reservoir Fluids Undergoing Gas Injection
- Karen Schou Pedersen (Calsep A/S) | Jawad Azeem (Calsep FZ-LLC) | Claus Patuel Rasmussen (Calsep A/S)
- Document ID
- Society of Petroleum Engineers
- SPE EOR Conference at Oil and Gas West Asia, 16-18 April, Muscat, Oman
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 4.3.3 Aspaltenes, 5.4 Enhanced Recovery, 5.4.2 Gas Injection Methods, 5.2.1 Phase Behavior and PVT Measurements, 5.2.2 Fluid Modeling, Equations of State, 1.8 Formation Damage, 4.1.2 Separation and Treating, 5.2 Reservoir Fluid Dynamics
- 1 in the last 30 days
- 295 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 28.00|
CO2 and hydrocarbon gas injection are interesting Enhanced Oil Recovery (EOR) techniques for oil reservoirs. Gas injection may initiate asphaltene precipitation in a reservoir. 1D compositional CO2 gas injection simulations have been conducted to find out where asphaltenes will precipitate and deposit. It was found that asphaltenes will precipitate in the transition zone between injection gas and oil. This transition zone will move forward continuously and no accumulation of asphaltene deposit will take place. Though deposited asphaltenes locally will plug reservoir pores and decrease permeability, this is unlikely to affect the oil recovery. The mobility of the gas and oil phases is high in the gas-oil transition zone where asphaltenes precipitate, and those high mobile phases will manage to bypass a small volume fraction of deposited asphaltenes. With an asphaltene phase present in addition to gas and oil the classical definition of a miscible gas drive cannot be fulfilled. Miscibility can however develop between an injection gas and an oil phase, which through contact with gas has been stripped for asphaltene components.
The oil industry sees injection of CO2 into oil fields as a way of getting rid of waste exhaustion gas and at the same time enhancing the recovery. Evaluations of whether an enhanced recovery can be achieved are often tied to the minimum miscibility pressure (MMP). The minimum miscibility pressure (MMP) is defined as the minimum pressure at which a fluid zone exists in which the gas and oil phases are fully miscible. Full miscibility means that one phase is observed no matter in what proportion the gas and the oil are mixed. Miscibility will generally be reached after a number of contacts between a reservoir oil and an injection gas. At the MMP the gas and oil compositions will be identical, i.e. the fluid developing MMP is a critical composition. A miscible drive is favorable because the miscible zone prevents the injection gas coming from behind in progressing and eventually causing a gas break through.
The oil industry has developed both experimental and simulation techniques for investigating how a reservoir oil will respond to gas injection. The displacement efficiency of an injection gas can be measured by carrying out a slim tube experiment (Shaik and Sah, 2011), which will provide information about the oil recovery as a function of pressure. Gas injection is most favorable if the drive is miscible. Provided only one gas and one oil (liquid) phase can exist, the lowest pressure (MMP) at which a miscible drive can form is observed as a bend on a plot of oil recovery versus pressure. The MMP can also be simulated using a multi-component tie-line method (Jessen et al., 1998) or a slim tube simulator.
For reservoir fluids, which as a result of gas injection will separate out an asphaltene phase, it is questionable whether the classical definition of miscibility can be met as it requires a critical fluid zone with only one phase present.
Alian et al. (2011) have performed CO2 flooding measurements on a Malaysian oil to study the effect CO2 precipitated asphaltenes on permeability and porosity. Both permeability and porosity were found to be reduced, but this will not necessarily have a great impact on the recovery from a field with CO2 injection. It depends on where in the reservoir the deposition takes place. If asphaltenes deposit in sections with a high oil saturation, the deposit is likely to somehow block the flow of oil. If on the other hand the deposit forms in sections dominated by CO2 injection gas, the impact on the oil recovery will be more limited because the mobility of the gas is so high that it will manage to bypass blocked pores.
|File Size||389 KB||Number of Pages||9|