Summary
Traditional decline methods such as Arps' rate/time relations and their
variations do not work for wells producing from supertight or shale reservoirs
in which fracture flow is dominant. Most of the production data from these
wells exhibit fracture-dominated flow regimes and rarely reach late-time flow
regimes, even over several years of production. Without the presence of
pseudoradial and boundary-dominated flows (BDFs), neither matrix permeability
nor drainage area can be established. This indicates that matrix contribution
is negligible compared with fracture contribution, and the expected ultimate
recovery (EUR) cannot be based on a traditional concept of drainage area.
An alternative approach is proposed to estimate EUR from wells in which
fracture flow is dominant and matrix contribution is negligible. To support
these fracture flows, the connected fracture density of the fractured area must
increase over time. This increase is possible because of local stress changes
under fracture depletion. Pressure depletion within fracture networks would
reactivate the existing faults or fractures, which may breach the hydraulic
integrity of the shale that seals these features. If these faults or fractures
are reactivated, their permeabilities will increase, facilitating enhanced
fluid migration. For fracture flows at a constant flowing bottomhole pressure,
a log-log plot of rate over cumulative production vs. time will yield a
straight line with a unity slope regardless of fracture types. In practice, a
slope of greater than unity is normally observed because of actual field
operations, data approximation, and flow-regime changes. A rate/time or
cumulative production/time relationship can be established on the basis of the
intercept and slope values of this log-log plot and initial gas rate.
Field examples from several supertight and shale gas plays for both dry and
high-liquid gas production, and for oil production were used to test the new
model. All display the predicted straight-line trend, with its slope and
intercept related to reservoir types. In other words, a certain fractured flow
regime or a combination of flow types that dominate a given area or play
because of its reservoir-rock characteristics and/or fracture-stimulation
practices all produce a narrow range of intercepts and slopes. An
individual-well performance or EUR can be derived that is based on this range
if the best 3-month average or the initial production rate of the well is
already known or estimated. The results show that this alternative approach is
easier to use, gives a reliable EUR, and can be used to replace the traditional
decline methods for unconventional reservoirs. The new approach is also able to
provide statistical methods to analyze production forecasts of resource plays
and to establish a range of results of these forecasts, including probability
distributions of reserves in terms of P90 (lower side) to P10 (higher
side).
© 2011. Society of Petroleum Engineers
View full textPDF
(
1,688 KB
)
History
- Original manuscript received:
30 September 2010
- Meeting paper published:
20 October 2010
- Revised manuscript received:
28 January 2011
- Manuscript approved:
24 March 2011
- Published online:
18 May 2011
- Version of record:
7 June 2011
View Cart
