C&C Reservoirs Publication

Polymer flood applications in offshore fields face more challenges than that of onshore fields. These challenges include limited platform space, costs to transfer polymer chemical, short service life, large well spacing, reduced polymer viscosity when mixed with sea water, and lack of analogs of practical polymer flood projects implemented in offshore. The above challenges make it’s hard to directly apply the onshore polymer flood technologies and experiences proved successful.

Taking five offshore viscous oil polymer flood projects as examples, this paper summarizes their implementation, production performance, reservoir management and lessons learned during pilot or field-wide polymer flood process. These projects cover cases in both shallow and dep water, and polymer flood beginning at early, interim, and mature development stages with water-cut < 20 %, between 20% and 60%, and >60%, respectively. Targets of these projects are all high-quality sandstone reservoirs with oil viscosity at reservoir condition varying from 11 to 88 cP. These projects were implemented in phase from single well injectivity test, pilot, to field, achieving an incremental recovery from 4% to 7%.

For the mature field cases, water-cut performance is characterized by typical funnel-shape, experiencing process of decreasing, stabilizing at low, then back to the high level. This corresponds to oil rate changes of the increasing, maintaining at a high, and then drop to low rate production. For the case of polymer flood starting at early development stage, the funnel-shape will never occur. Instead, water-cut rises sustainably, while its increasing trend is obviously arrested.

Effective polymer flood process shows increased injection pressure and resistance factor, dropped water-intake index and improved injecting profile. Production responses to polymer injection is generally earlier than polymer breakthrough timing with average responding duration of 2.6 years comparing with that of average polymer breakthrough of 4.8 years in specific cases.

Lessons learned are: (1) early polymer flood could be a strategy for offshore field, which recovers oil in short time, saves the cost of production fluid processing as well as achieves relatively higher recovery factor; (2) mechanic degradation at the near wellbore is the main source of polymer degradation due to permeability impairment caused by poor quality produced water injection. Rather than the most popular HPAM, the salinity and shearing resistance polymer such as hydrophobic associated polymer is a better solution; (3) effective reservoir management such as zonal polymer solution injection and gel plus polymer flood injection benefits for improving polymer flooding.