Granite Oil Corp GXOCF

RE:Facts for rigpig2

[not4anymore]

Key Facts and Drilling Model Although technically well-established and largely de-risked into a “manufacturing”-style development mode, Ferguson remains a young asset offering many years of further development in the core pool as well as growth potential in the property’s barely explored western lands. Upon Granite’s founding in May 2015, Ferguson comprised: •44 horizontal wells on-production plus five injector wells, all Company-operated; •547 sections or 350,000 acres of Bakken lands at 100 percent working interest, out of total landholdings of 407,183 net acres; •Company-owned infrastructure including: •Single-well and multi-well producing sites; •8" gas gathering lines, field compression, a Company-owned gas plant and metering station on the TransCanada system; •8" oil flow lines; •A central battery with capacity of 8,000 bbls per day and 20,000 bbls of storage; and •Gas and water reinjection wells, gas compression and high-pressure injection lines for the EOR program; •17 million boe of proved plus probable reserves plus approximately 479 million barrels of discovered and undiscovered oil initially in place; •Extensive shallow gas potential to support EOR expansion and long-term sustainment; and •A future horizontal well inventory of 162 drilling locations. The property’s comprehensive infrastructure will enable Granite to allocate the large majority of its capital investment to drilling and completing wells, as well as further building out EOR capacity. Granite’s horizontal development model has the following main parameters: •Drilling from multi-well pads with established surface equipment and flow lines in the core pool area; •Use of monobore well drilling technology and sliding-sleeve completions technology; •Horizontal legs of 2,000-2,500 metres; •Typically 30+ fracturing stages; •10-20 tonnes of proppant per stage; •Nitrified foam fracturing fluid; •Targeted first-year well productivity of 190 bbls per day; and •Targeted costs to drill, complete and tie-in of $2.8 million per well. The production decline in the core pool EOR area is estimated at 22 percent per year. An estimated five horizontal wells per year are needed to maintain production at approximately 4,000 bbls per day, with 10 wells achieving an estimated 12 percent year-over-year production growth.