Case Study: Evaluation of Horizontal Well Multistage Fracturing in the Viking Oil Formation
- Arvil Carl Mogensen (WestFire Energy Ltd) | Robert Clayton Bachman (Taurus Reservoir Solutions Ltd) | Peter Peter Singbeil (Introspec Energy Group Inc)
- Document ID
- Society of Petroleum Engineers
- SPE Canadian Unconventional Resources Conference, 30 October-1 November, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 5.5 Reservoir Simulation, 5.8.6 Naturally Fractured Reservoir, 5.4.1 Waterflooding, 5.7 Reserves Evaluation, 4.6 Natural Gas, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.5.4 Multistage Fracturing, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.1.5 Processing Equipment, 4.2 Pipelines, Flowlines and Risers, 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.7.2 Recovery Factors, 5.6.9 Production Forecasting, 2.4.3 Sand/Solids Control, 5.8.2 Shale Gas, 5.6.4 Drillstem/Well Testing, 3 Production and Well Operations, 4.3.4 Scale, 1.6.9 Coring, Fishing, 1.6 Drilling Operations, 1.4.3 Fines Migration, 2 Well Completion, 1.6.6 Directional Drilling
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The Viking formation in Western Saskatchewan and East to Central Alberta is comprised of many different oil pools. These plays have seen resurgence in activity over the last 6 years as a result of the horizontal multi-stage fracturing revolution. A wide variety of fracturing technologies have been applied, encompassing open versus cased hole, variable proppant tonnage per stage and fracture spacing along the wellbore. How does the average company make meaningful decisions as to how to stimulate their wells? There is a need to make sense of the production response of the wells given reservoir quality differences, primarily permeability variation, and the variety of fracturing technologies being applied. The paper will develop a workflow which integrates publically available production data to first identify a production rate metric. This metric can be used for production forecasting and as a basis to compare area and pool production performance. Combining this information with well ownership leads to a preliminary assessment of whether production success is due solely to the reservoir, or the drilling and completion strategy applied.
The unconventional oil-bearing Cretaceous Viking Sand formation trends northwest to southeast from Redwater, just northeast of the city of Edmonton in the province of Alberta, through to west central Saskatchewan near the town of Kindersley, a distance of about 800 km, as shown on the map in Figure 1.
Within this trend are five fields in which exploitation of Viking formation oil production has taken place. The fields include; Redwater, Halkirk, Provost, Dodsland and Plato. Exploitation of the light crude (37-38 API) from the Viking formation first began in Redwater and the greater Dodsland areas in the early 1950's, followed by Provost in the early 1960's, and Plato in the latter 1960's, and finally Halkirk in the early 1980's. All the wells at the time were drilled vertically, eventually downspaced to 16-hectare (40 acres) well spacing in most areas. Wells were fracture stimulated using treatment designs reflective of the hydraulic fracture technology employed at the time. Proppant tonnage of up to 45 tonnes, treatment concentrations of 600 kg/m3, feed rates of about 8 m3/minute were typically applied. Post fracture stimulation production rates in all the areas showed steep oil production declines that reached the economic limit within a matter of a few years. Many wells were stimulated a number of times, and operators were often rewarded with a restoration of production that approached initial rates. However the rates quickly declined in a manner similar to the established trend. Very little produced water was associated with the oil production. The majority of Viking production is from primary production from below the bubble point. When reported, GOR's are low and do not increase substantially with time.
Efforts to arrest the decline in oil production rate by waterflooding were made in two pools in the greater Dodsland area; a line-drive was implemented in the Dodsland field and a pattern waterflood in Eagle Lake. The pressure support provided from waterflood helped sustain the rate of production for some wells but waterflood response was not universal, and oil rates remained modest. Recovery factors in both primary and waterflood areas are low.
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