An Interim Case Study of an Alkaline-Surfactant-Polymer Flood in the Mooney Field, Alberta, Canada

Abstract

Chemical Enhanced Oil Recovery (CEOR) use is expected to increase as more production companies implement tertiary oil recovery methods. This case study provides an outline of the process used to determine the applicability of an Alkaline-Surfactant-Polymer (ASP) flood, how the ASP chemical package was selected and tested, and the current field trial status. The selected field for this project is the low temperature Mooney field in north-central Alberta, Canada, producing ~16° API gravity oil with a viscosity of 150 to 1,500 mPa-s from the Cretaceous Bluesky sand formation at a depth of approximately 900 meters. In 2006 a waterflood pilot test recovered an incremental 3% of the original oil in place (OOIP) over the primary production recovery (~4 to 5%). A three well polymer-only pilot was started in 2008 for 14 months and showed a total recovery of 18% OOIP suggesting a tertiary recovery method could be more successful than a waterflood. An independent laboratory tested multiple ASP packages, formulated with various surfactant types, either NaOH or Na2CO3 as the alkali in softened injection water, and with a partially hydrolyzed copolymers of acrylamide and acrylic acid. This independent reservoir screening identified several ultra-low interfacial tension ASP chemical package candidates, and core flooding confirmed increased oil recovery. Low chemical concentrations were specifically tested to minimize ASP chemical costs and downstream issues with emulsions. Economics were promising enough to proceed with company and Canadian approvals for ASP Phase One field implementation. Commercial injection began September 2011. The Phase One ASP scheme consists of 25 injectors and 26 producers. Production from the ASP flooded area increased from approximately 175 barrels of oil per day (BOPD) in summer 2011 to a current high of ~2600 BOPD in December 2013, a period of 30 months. ASP chemical injection is continuing. Some injection delays have been caused by operational issues (water source and pipeline/facility modifications). These promising oil recovery results allowed Phase Two to be approved, and it is slated to be completed in 2014. Phase Three development is in the planning stage including drilling 16 additional primary horizontal wells. The ASP flood of the Mooney field is a multi-well ASP flood that is progressing well but is still in the preliminary stages of data collection. The reservoir will continue to be monitored over the coming years to develop a comprehensive analysis of the tertiary oil recovery and how it compares with the initial laboratory ASP test results and predictions.

Supramolecular Polymer-Surfactant System for Heavy Oil Recovery

“…Furthermore, the low concentration of anionic surfactant contained in the SAP-AP1 formulation reduces the interfacial tension (IFT) of the oilbrine system from 30 [45] to 0.032 dynes/cm. This remarkable reduction in IFT decreases capillary forces, which facilitates the detachment and mobilization of oil during SAP-AP1 flooding [46,47]. Therefore, the SAP-AP1 system produces incremental oil recovery by the synergistic effect of greater mobility control functionality and by decreasing the IFT of the oil-brine system.…”

Half-Century of Heavy Oil Polymer Flooding from Laboratory Core Floods to Pilot Tests and Field Applications

“…Following the success, an application of polymer and ASP flooding has developed in other parts of the reservoir. Recently, the decision has been made to move from polymer flooding to a larger scale ASP flooding (Watson et al 2014).…”

Polymer Flooding of Heavy Oil - From Screening to Full-Field Extension

“…Their behavior is not yet well understood (Dupuis et al 2012, Seright et al 2011. They have seen little use in field projects so far but in heavy oil they have been used successfully in the Mooney field in Canada (Watson et al 2014), in Phase 2 at Bodo (Renouf 2014) and in Bohai Bay (Kang et al 2011). …”

“…In Mooney polymer flood has been abandoned and ASP is instead implemented at a large scale (Watson et al 2014). Field extension has also apparently been approved in Tambaredjo for 36 new injection wells (Staatsolie 2014).…”

“…In the Mooney polymer pilot for instance the oil rate increased but the water breakthrough was very severe; this is probably due to heterogeneity or to the high injection rate required by the regulator (Watson et al 2014, Delamaide et al 2014a). In Pelican Lake some wells also have conformance issues.…”