Stolberg Example

Why have Foothills reservoirs as part of the asset base: the Stolberg Example

Approximately 10 years ago, the Tuktu team commenced exploration in the foothills, having spent many years working in foothills-focused major companies such as Taliman Energy and British Gas. These companies were looking for large gas fields, each with trillions of cubic feet of recoverable gas, which was necessary to pay for the initial processing facilities, pipelines and access roads (Figure S1). Shell, for example, built three deep-cut sour gas plants to handle the processing of liquids-rich giant sour gas fields in the southern Foothills. Individual wells from some of these fields have produced up to 0.5 Tcf each. However, drilling costs could be very high for such wells, particularly where gas fields contain significant H2S gas. The cost to find and produce sour gas is exasperated by processing costs, which is due to many factors, including significant CO2 release (thus high carbon tax) and high costs to operate and maintain specialized plant equipment.

Figure S1. Regional cross section through the southern Foothills showing deeper sour targets (Paleozoic), which were exploited by major oil and gas companies. In this case Shell mostly drilled the Waterton/Carbondale Trend (blue and purple-Paleozoic) which have produced some 4.7 Tcf of mostly sour liquids-rich gas. The Pincher Creek Trend has produced 0.5 Tcf. The brown beds (Cretaceous-Jurassic) above the Pincher Creek sour field is the focus of light oil development within Tuktu Resources.

However, due to the efforts of these large companies, large road and pipeline infrastructure was installed in the foothills. The deeper wells also afforded a closer look at shallower reservoirs (“bypass” reservoirs), which tend to be sweet and sometimes oil bearing. This reduces the need for expensive processing plants and other associated sour infrastructure. Keying on these shallower zones of bypass and structural complexity, the team recognized a potential fairway in the central Alberta Foothills. They recognized limited porosity within the Cardium Formation in a deviated well (8-31-42-15W5). This well has produced 35,000 bbl of oil with an initial production rate of 33 bbls/d, despite fracture stimulation. This reservoir is at about 1,700 m depth and is under pressured with respect to normal hydrostatic gradient (Figure S3).

Figure S3. Cross section through the Stolberg pool.

Prior to spudding the first well in the Stolberg area, the team though that, if they could drill a limited horizontal along the folded Cardium Formation, natural fractures could be intersected, and the well could yield encouraging initial production rates. These assumptions proved correct, and the first horizontal well (100/10-29-42-15W5) flowed to surface without stimulation at an average initial rate of 1,129 bbls/d for the month of June, 2012. Over the course of drilling the Cardium during the subsequent 12 to 24 months, the team realized that the structure was quite large, some 8km in total length, with a fold amplitude that was several 1,000 m high. Limbs of this fold are very steep, locally overturned, and the reservoir is transparent to seismic imaging. Also, the structure appears to be “filled-to-spill” and with a limited gas cap. Further, drilling demonstrated that there were several complexities in the structure, and the reservoir was locally partitioned by several faults. All subsequent horizontal or highly deviated wells mostly targeted the near-vertical, fractured fold limbs. The largest producing well in the field is anticipated to produce over 800,000 bbls/oil and had initial rates of more than 1,200 bbls/day for several months (Figure S4).

Figure S4. Single unstimulated well in highly deformed and fractured Stolberg Oil Pool. This well was drilled by Tuktu team members along the steep limb of the Stolberg folded oil pool and intersected many natural fractures. The unstimulated well will produce more than 700,000 bbls, and which was less than $3 million to drill and complete.

All wells in the field drilled subsequent to the discovery well were unstimulated. Primary porosity, based on logs and core, is only about 6%, but the high number of natural fractures creates good permeability, thus high well deliverability without stimulation. The field is expected to produce some 5.75 milion barrels of oil (Figure S2).

Figure S2. Stolberg Foothills light oil pool, location cumulative oil production.