EUR Forecasting via Flow Capacity Correlation
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Solution Overview
Problem
Existing methods for forecasting estimated ultimate recovery (EUR) in unconventional shale reservoirs are inadequate, particularly for wells with tight rock and multi-fractured horizontal wells, leading to inefficient resource utilization due to inappropriate forecasting.
Innovation Solution
A computer-implemented method that uses flow capacity, specifically gas flow capacity and water flow capacity, as a parameter to estimate EUR based on early-time data, correlating these capacities with EUR to predict future production behavior and inform operational decisions.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Measurement precision
If legacy forecasting techniques are used for unconventional shale reservoirs, then traditional EUR prediction methods are applied, but the forecasting accuracy deteriorates due to the unique characteristics of tight rock and multi-fractured horizontal wells
Solution Approach 1:
The patent changes the forecasting parameter from traditional cumulative production metrics to flow capacity (k×w) derived from early-time flowback data. This parameter transformation enables accurate EUR prediction for unconventional reservoirs by capturing the dominant linear flow mechanism characteristic of multi-fractured horizontal wells in tight rock, resolving the contradiction between maintaining traditional methods and adapting to new reservoir characteristics
Solution Approach 2:
The patent performs EUR forecasting during the early flowback period (first few weeks) rather than waiting for extended production data. By calculating flow capacity from initial flowback rates and applying the correlation EUR = 0.0032 × (k×w)^1.3, the method provides preliminary EUR estimates that guide development decisions before significant production data is available, addressing the need for early evaluation in unconventional settings
2Loss of time
If early-time flowback data is used for EUR evaluation, then decision-making time is reduced, but the reliability of forecasting deteriorates due to limited data availability
Solution Approach 1:
The patent extracts the dominant flow mechanism signal from early-time flowback data by calculating flow capacity (k×w), isolating the linear flow component that characterizes unconventional reservoir drainage. This extraction method filters out noise and transient effects, providing reliable EUR estimates from limited early data without requiring extended production history, thus resolving the contradiction between early evaluation and forecasting reliability
Solution Approach 2:
The patent introduces flow capacity (k×w) as an intermediary parameter that bridges early-time flowback data and ultimate recovery prediction. This intermediary captures the essential drainage characteristics of multi-fractured wells and serves as a robust predictor of EUR even with limited data, mediating between the constraints of early evaluation and the needs for reliable forecasting
3Measurement precision
If flow capacity is used as the forecasting parameter, then EUR prediction from early data is improved, but the complexity of calculating and correlating flow capacity increases
Solution Approach 1:
The patent merges permeability (k) and fracture width (w) into a single composite parameter called flow capacity (k×w). This consolidation simplifies the forecasting methodology by combining multiple difficult-to-measure parameters into one that can be derived from readily available flowback rate data, reducing operational complexity while maintaining high EUR prediction accuracy through the correlation EUR = 0.0032 × (k×w)^1.3
Data Source
AI summary
Embodiments herein relate to a technique that may include identifying historical data related to at least one remote well. The technique may further include identifying, based on the historical data, a correlation between gas flow capacity and estimated ultimate recovery (EUR) of the at least one other well. The technique may further include identifying gas flow capacity of a well. The technique may further include predicting, based on the gas flow capacity of the well and the identified correlation between gas flow capacity and EUR of the at least one other well, EUR of the well. The technique may further include operating the well based on the predicted EUR. Other embodiments may be described or claimed.