Determination of fracture surface area from flowback data: A case study for northern Montney play, British Columbia, Canada
| Autor: | Al Moghadam, Noga Vaisblat, Nicholas B. Harris, Rick Chalaturnyk |
|---|---|
| Rok vydání: | 2021 |
| Předmět: |
Suction
Petroleum engineering Capillary action 020209 energy Energy Engineering and Power Technology 02 engineering and technology Geotechnical Engineering and Engineering Geology Fuel Technology Brittleness Hydraulic fracturing 020401 chemical engineering 0202 electrical engineering electronic engineering information engineering Fracture (geology) Imbibition Dew Stage (hydrology) 0204 chemical engineering Geology |
| Zdroj: | Journal of Natural Gas Science and Engineering. 87:103791 |
| ISSN: | 1875-5100 |
| DOI: | 10.1016/j.jngse.2020.103791 |
| Popis: | We develop a two-phase (gas/water) flow model to simulate water imbibition into the face of a hydraulic fracture. The model incorporates water suction potential values measured with a dew-point psychrometer, which has distinct advantages over standard mercury injection tests, to measure water suction potential in tight rocks. The model accurately predicts water imbibition into core plugs from the Montney Formation under lab conditions. We then apply the model to simulate water leak-off per unit fracture area during a typical frack stage and the subsequent soaking period. Our results show that a 0.3 m invaded zone develops from the fracture face into the formation at the end of 30 days of soaking. High water saturation in the invaded zone dissipates into the rock after two months of production, due to high capillary pressures (suction potential). We selected 120 wells in close proximity in the northern Montney play to build a case study. Pertinent load recovery data such as water injected, water recovered, and soak-time were collected for each well. Using the simulation results and field data, we estimated the fracture surface area created or stimulated during hydraulic fracturing for each well. The wells’ production performance shows a clear relationship with the calculated fracture surface area of the wells, which averaged 250,000 m2 per stage. This methodology can be used to assess the future well performance immediately after flowback. Applying this method to a region can assist operators in identifying sweet spots in their assets in terms of presence of brittle rocks or natural fracture networks. In addition, the estimate of fracture surface area can constrain discrete fracture models. |
| Databáze: | OpenAIRE |
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