CALGARY, ALBERTA -- (Marketwired) -- 06/13/13 -- Southern Pacific Resource Corp. ("Southern Pacific" or the "Company") (TSX: STP) today provided an operational update for the month of May, 2013 with respect to the Company's STP-McKay and STP-Senlac Thermal Projects.
STP-McKay Thermal Project - High Pressure Steam Stimulation ("HPSS")
During the month of May, the Company focused its operations on the successful implementation and completion of a High Pressure Steam Stimulation ("HPSS") test on one of the existing 12 steam-assisted gravity drainage ("SAGD") well pairs at STP-McKay.
As previously stated, production ramp up at STP-McKay has been slower than anticipated, largely a result of delays establishing sufficient horizontal communication between injector and producer on some of the well pairs. After analyzing the production data over the past seven months, the Company believes that the conformance delay is occurring due to several factors including sand grain sorting, higher bitumen saturation levels, lower operating pressures and wider well pair configuration (Pad 1 was drilled with a wider average separation between the injector and producer in order to capture underlying oil which would otherwise have been stranded). The Company's reservoir modeling identified the HPSS as a low cost procedure that would accelerate horizontal communication between the two wellbores by geo-mechanically expanding and re-aligning the sand matrix to promote improved communication pathways, thus reducing the time required to enhance the well pair's horizontal conformance.
The Company submitted an application to the Energy Resources Conservation Board ("ERCB") in March, 2013 to conduct a HPSS test and it received approval to proceed in late April. The approval of the test allowed Southern Pacific to inject a finite volume of steam at a pressure that exceeds the current maximum operating pressure of the project. A few weeks of test preparation in the field were required, which included shutting in the test well pair and the offset well pair to stabilize and monitor pressures, and calibrate the surrounding observation wells. The test commenced on May 21st and was completed on May 29th. The HPSS was performed on the well pair 1P1, the furthest to the east of the existing 12 well pairs. This well pair was chosen as it has been one of the well pairs which to date had not demonstrated significant communication between the injector and producer well bores. In addition, this well is located underneath an existing horizontal observation well drilled into the upper Wabiskaw zone, which was used to monitor and verify pressure impacts to the overlying caprock. Following the HPSS, the well pair was allowed to de-pressure and cool, and subsequently placed on SAGD production on June 4th. While the results of the test are still being evaluated, initial results are very encouraging, as evidenced by the following:
-- The well pair has been operating in steady SAGD mode since June 4th; this well pair had never operated in steady SAGD mode prior to the stimulation. The rate has been steadily improving to a current fluid rate of approximately 750 barrels per day ("bbl/d") with a 25% oil cut. The oil cut continues to improve as the stimulation fluid (steam condensed to water) is recovered;-- A significant improvement in horizontal communication along the length of the injector and producer wellbores was established during the HPSS;-- There were no pressure or temperature disturbances measured above the well pair from the overlying horizontal Wabiskaw well, nor laterally from the offset vertical observation wells; and-- The test planning, protocol, execution and monitoring were conducted in a manner that was safe, protected the wellbore integrity and provided the information necessary to repeat this process on other well pairs at negligible cost.