| dc.description.abstract | About 60% of oil still lays trapped in the reservoir even after primary and secondary recovery processes have been completed. This trapped oil could be residual or by-passed oil. Residual oil occurs as a result of high capillary action of water that keeps the oil immobile. One way ofrecovering this capillary trapped oil is by flooding the reservoir with surfactants. Surfactants are surface active agents that act on the interface between oil and water with the aim of reducing the interfacial tension between them thereby causing trapped oil to flow.
In the Norne field E-Segment, pockets of oil are still trapped after water flooding for a number of years, especially in the Ile and Tofte Formations which holds about 80% of oil in the Norne E-Segment.With increasing water cut and reduced oil production, it becomes obvious that water flooding alone cannot recover the oil effectively, thus a need for an enhancing agent, like surfactant.
When flooding the reservoir with surfactants, it is very important to ascertain the right quantity of surfactant that would yield the maximum recovery without unnecessary waste of the surfactant because of the high cost.
In this thesis, a series of screening methods were used in order to come up with the appropriate surfactant quantity and concentration that would yield maximum recovery of trapped oil at a minimal cost.
The first step was modeling of continuous surfactant flooding into the reservoir for a period of 4 years and 7 years respectively. It was discovered that flooding the reservoir for a period of 7 years did not necessarily lead to a better oil recovery than flooding for 4 years. Also, flooding for 7 years led to a high quantity of surfactant injection into the reservoir and a subsequent production of same at the producer well E-2H. A situation like this is not desirable because of the cost of surfactants.
Having established that a 4-year surfactant injection period is preferable to a 7-year period, the second step was to compare between slug injection of surfactants at 2 months intervals and at 6 months intervals respectively. It was discovered that injecting surfactant slug every 2 months(that is 3 times in a year) did not necessarily do better than injecting at every 6 months interval.Also, injecting surfactant every 2 months required very high quantities of surfactants to meetthe demand. Also there is a high production of surfactant at the producer well.
Having confirmed through reservoir modeling that surfactant slug injection for a 6-month interval is better than that of a 2-month interval, the next step was to compare between continuous surfactant injection for 4 years and surfactant slug injection for 4 years (at 6-monthinterval). Continuous surfactant flooding was discarded in favor of the slug injection because of the high quantity of surfactant needed compared to the quantity needed in case of slug injection. Also, continuous surfactant flooding did not necessarily lead to better oil recovery than slug surfactant flooding.
Having established that the most effective method to inject surfactant into the reservoir is slug injection for 4 years at 6 months interval, the next challenge was to determine the appropriate surfactant concentration that would be needed for optimal recovery of residual oil. Eight (8)different surfactant concentrations were modeled and these include concentrations at 10kg/m3, 20kg/m3, 30kg/m3, 40kg/m3, 50kg/m3, 60kg/m3, 80kg/m3 and 100kg/m3. Net present value (NPV) was used to determine the best concentration that would yield the maximum profit. The concentration of 10kg/m3 gave the best NPV.
Having discovered that the surfactant slug of 10kg/m3 concentration would yield better recovery, the next task was to check the effect of drilling new wells or re-completing already drilled wells on recovery.
Four cases were considered;
1. Original wells without injection of surfactant slug.
2. Original wells with surfactant slug injection.
3. Injecting surfactant slug into original wells in addition to a newly drilled well.
4. Injecting surfactant slug into wells that had been re-completed/extended in addition toa newly drilled well.
From the economic analysis, it was discovered that recompleting the wells in addition to a new well gave the best NPV followed by the case where surfactant was injected to the original well with a newly drilled well. All these options did better than the base-case where surfactant was not injected at all.
The case of re-completion of the wells gave a better recovery because the re-completed wells were made to inject surfactants directly into the Ile and Tofte formations which hold about 80% of oil in the reservoir.
In conclusion, surfactant flooding is a good option for the Norne field E-Segment especially when the Ile and Tofte formations are targeted.
Based on this conclusion, it is recommended that the right surfactant structure that would be suitable for the Norne field E-Segment fluid and rock property be developed in the laboratory (this thesis involved only simulation studies). It is also important that up-scaling the appropriate laboratory identified surfactants to a field-scale usage be done correctly.Studies have shown that the reason why many surfactants that seem to do well in the laboratory but do not do well in the field is due to incorrect up-scaling.
The timing of surfactant injection into the Norne field E-Segment is also recommended to be early in the life of the field. This is because of the heterogeneous nature of the field.Injection of surfactant at a later time might not lead to optimum oil recovery.
Thus, simulation studies show that surfactant injection, at the appropriate time is good for the Norne E- Segment. | nb_NO |
