CO2 gas injection is an interesting EOR technique for mature oil fields and can also be a way to decrease emission of a greenhouse gas. When used as EOR gas, an optimum recovery will only be achieved if the injected CO2, possibly after a number of contacts, becomes miscible with the oil. Whether miscibility develops in a reservoir is determined by reservoir conditions, permeability and reservoir fluid composition.
A number of different PVT experiments have been designed to deal with gas injection including swelling, multi-contact, equilibrium contact and slimtube tests. A slimtube experiment gives a measure of the percent recovery as a function of reservoir pressure and a measure of the minimum miscibility pressure (MMP), while the other mentioned experiments provide information on the changes in phase properties and phase compositions after one or more contacts between gas and oil.
The injected CO2 may cause the reservoir fluid to split into two separate CO2-rich liquid phases. A liquid-liquid split can be difficult to account for in reservoir evaluations, since most compositional reservoir simulators only handle one liquid phase.
Dedicated tie-line MMP simulations are becoming increasingly popular as a fast alternative to full 3D or 1D compositional reservoir simulation studies. The MMP options further have the advantage that it is possible to tune the EoS model to match a particular minimum miscibility pressure.
The targets of the project were:
- Evaluate C7+ characterization procedures suited for CO2 rich fluids with emphasis on
- Analysis of differences between tie line MMP’s and slim tube MMP’s.
- Most efficient regression parameters.
- Effect of component lumping.
- Handling of CO2 introduced liquid-liquid splits.
Lindeloff, N.L., Mogensen, K., Pedersen, K.S., Tybjerg, P., Noman, R., Investigation of Miscibility Behavior of CO2 rich Hydrocarbon Systems – With Application for Gas Injection EOR, SPE 166270-MS, SPE Annual Technical Conference and Exhibition, New Orleans, LA, USA, 30 September – 2 October, 2013.
A satisfactory asphaltene model must quantitatively handle gas-oil-asphaltene equilibria at reservoir and production conditions. It must be sensitive to pressure to represent the phase splits occurring at isothermal conditions as a result of a pressure reduction. This requires a very accurate description of the volumetric behavior of both the oil and the asphaltene phase at high pressures. An important aspect of asphaltene phase behavior is the possible asphaltene precipitation in connection with Enhanced Oil Recovery (EOR). The model should quantitatively assess the influence on the asphaltene onset pressure of a possible injection of natural gas, N2 or CO2.
The available asphaltene models were reviewed and the most promising model was found in the PC-SAFT model (Perturbed Chain Statistical Association Fluid Theory).
Hustad, O. S., Jia, N.J., Pedersen, K.S., Memon, A., Leekumjorn, S., High Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of GoM Oil Mixed with Nitrogen, SPE Reservoir Evaluation & Engineering 3, 2014, pp. 384-395.
Characterization of Heavy Oils
A characterization procedure for heavy oils was developed that successfully modeled the phase behavior of heavy oil mixtures with an API Gravity as low as 10. It was further clarified how to avoid the simulated liquid-liquid splits that often cause problems for compositional reservoir simulators. In the same project the Corresponding States (CSP) viscosity model was extended to also cover heavy oils. Some of the oils dealt with in the project had viscosities of several thousand centipoises.
Krejbjerg, K., Pedersen, K.S., Controlling VLLE Equilibrium with a Cubic EOS in Heavy Oil Modeling, 57th Annual Technical Meeting of the Petroleum Society (Canadian International Petroleum Conference), Calgary, Canada, June 13-15, 2006.
Lindeloff, N., Pedersen, K.S., Rønningsen, H. P., Milter, J., The Corresponding States Viscosity Model Applied to Heavy Oil Systems, Journal of Canadian Petroleum Technology 43, 2004, pp. 47 - 53.
Hydrate Kinetics in Pipelines
A new algorithm was developed for solving mass transfer limited hydrate growth in a pipeline environment. The hydrate kinetics model used was originally developed by Skovborg based on well-controlled laboratory experiments carried out at constant temperature and with a constant interfacial area between water and hydrocarbons. To apply the growth model for pipeline transport, variations in the interfacial area and heat effects were taken into consideration.
The new algorithm includes three parts,
- An implicit procedure for solving the differential equations governing mass and heat transport
- A hydrate flash algorithm that works for an aqueous phase with dissolved hydrocarbons. The flash does not consider the free hydrocarbon phases, which in a system with hydrate growth are not necessarily in equilibrium with the water phase.
- A pipeline discretization algorithm, which assures that the mass and heat transport equations are solved with good accuracy and speed.
Boesen, R.R., Sørensen, H. and Pedersen, K.S., New Approach for Hydrate Flash Calculations, Proceedings of the 8th International Conference on Gas Hydrates (ICGH8-2014), Beijing, China, 28 July - 1 August, 2014
Hadsbjerg C. and Krejbjerg K. , Challenges in Hydrate Plug Prevention in Pipelines Seen Over the Lifetime of a Field ASME 2009 28th International Conference on Ocean, Offshore and Arctic Engineering (OMAE2009), 7, 2009, pp. 435-443.
Hadsbjerg, C., Creek, J. and Delle-Case E., "Transportability and Plugging Risk for Under-Inhibited Natural Gas Hydrate Systems". 7th International Conference on Gas Hydrates (ICGH 2011),
Edinburgh, Scotland, United Kingdom, July 17-21, 2011.
Sonne, J. and Pedersen, K.S., Simulation of Hydrate Growth in Steady State Flow Lines, BHR 14th International Conference on Multiphase Production Technology, Cannes, France, June 17 - 19, 2009.
Compositional Variations in Reservoirs with a Thermal Gradient
Gravity will make the concentration of heavy molecular weight compounds increase with depth. The actual project revealed that the same is the case in a reservoir with a positive thermal gradient with depth. Calsep developed a model based on irreversible thermodynamics matching the observed compositional trend.
Pedersen, K.S., Lindeloff, N., Simulations of Compositional Gradients in Hydrocarbon Reservoirs under the Influence of a Temperature Gradient, SPE 84364, SPE ATCE, Denver, Co. Oct. 5 - 8, 2003.
Pedersen, K.S., Hjermstad, H.P., Modeling of Large Hydrocarbon Compositional Gradient, SPE 101275, Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, November 5-8, 2006.