Abstract

Conventional primary and secondary water flooding of Deepwater Gulf of Mexico (GOM) reservoirs typically result in substantial un-recovered oil providing an attractive target for enhanced oil recovery (EOR) processes. One of the challenges of applying EOR gas injection in these offshore reservoirs is the h igh oil asphaltene content. Anadarko Petroleum Corporation and Schlumberger have jointly investigated the effects of gas addition on the phase behavior of oil, especially its effect on asphaltene precipitation and deposition. The study focuses on the experimental results from various tests showing the instability of asphaltenes in oil from various gas injection scenarios.

Three common EOR injection gases: nitrogen (N2), carbon dioxide (CO2) and methane (CH4) were studied. N- heptane was (n-C7) also included for comparison of solids phase behavior during depressurization. Most asphaltene laboratory testing use n-C7 at ambient conditions, whereas asphaltene precipitation occurs with change in pressure and temperature during reservoir depletion processes.

The study collected PVT and flow assurance data for original live fluid and for additions of N2, CO2, CH4 and n- C7 at high pressure and temperature conditions. Measurements include asphaltene onset pressure (AOP), saturation pressure (Pb), swelling tests and asphaltene deposition tests. Other basic measurements of the corresponding dead oil include SARA analysis, viscosity, density and fluid characterization. Fluids from the field presented a compositional variation with a variety of asphaltene contents from 4 to 15.5%.

Results of experimental flow assurance assessments revealed the black oil has high propensity for asphaltene precipitation due to addition of injected gas. The addition of N2, CO2 or CH4 significantly aggravates the asphaltene precipitation condition of these fluids.

The comparison between the three gases showed that, when added in the same mole proportion, N2 was the strongest precipitant followed by CH4.

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