Reservoir Evaluation and Production Optimization Special Interest Group Luncheon:
Comparison of Numerical vs Analytical Models for EUR Calculations and Optimization in Unconventional Resources
Date: Tuesday, 13 June 2017
Speaker: Jim Erdle, Computer Modelling Group
Location: Calgary Petroleum Club
Time: 11:30 - 1:00 pm
Cost: $45 SPE Members, $55 Non-members, $15 Students
Analytical models available in Rate-Transient-Analysis (RTA) packages are widely used as fast tools for history matching and forecast in unconventional resources. In addition, recently, there has been an increasing interest in numerical simulation of unconventional reservoirs. In this study, we use both methods to history match fractured unconventional wells, followed by forecast calculations. This study aims to reveal large differences in Estimated Ultimate Recovery (EUR), predicted by analytical models and numerical simulation in unconventional reservoirs.
First, we consider a single-phase shale oil reservoir as a base case for this study. The base case also satisfies other assumptions inherent in analytical models such as homogenous reservoir properties and fully-penetrating planar fractures with constant half-length and conductivity. An excellent match between results of two methods for the base model validates the simulation approach. We then impose different real-world deviations from RTA assumptions and investigate reliability of EUR predictions made by both approaches. We also examine dry gas and gas condensate shale reservoirs. In all cases, historical data and reference EURs are derived from fine-grid simulations.
Example results show that, in the presence of real-world deviations from RTA assumptions, analytical models can still match the historical production data; however, key reservoir and fracture parameters need to be modified drastically to compensate lack of sufficient physics in analytical models. Results show that these history-matched models are not predictive for future production, providing highly pessimistic EURs in most real-world scenarios. For the cases presented in this study, analytical models under-predicts EURs by 10-20% although history match of two-year production looks good. This error in EUR increases drastically (up to 50-60%) as the length of historical data decreases from 2 years to 3 months.
For all cases, we also apply an efficient simulation workflow for probabilistic forecasting of brown fields. This workflow provides multiple history-matched models that are constrained by historical production data. The probabilistic forecast provides P90 (conservative), P50 (most likely), and P10 (optimistic) values for EUR. In all examples, range of P90 to P10 values includes the reference EUR and the P50 values are within 7% error of the reference EUR.
Dr. Erdle is CMG’s Vice President for software sales and support for the USA and Latin American. He has 42 years of industry experience, primarily in reservoir and production engineering-related positions within the services and software segments of the E&P industry, since graduating from Penn State with BS and PhD degrees in Petroleum Engineering in ’71 and ’74.
Jim has been involved in several recent SPE papers on the subject of modelling unconventional wells (SPE #’s 125530, 125532, 175122, 180209, 180974), and is the author of Chapter 8 (Application of Numerical Models) in the 2016 SPEE Monograph # 4 (Estimating Ultimate Recovery of Developed Wells in Low-Permeability Reservoirs).
The SPE would like to thank our sponsor: Repsol
Repsol is a key player in the Canadian oil and gas industry. Their Canadian interests are focused on liquids and gas assets in the Greater Edson area of Alberta, conventional heavy oil assets in the Chauvin area of Alberta/Saskatchewan, and liquids-rich gas assets in Alberta’s Duvernay play. They are also the majority owner and manager of Canaport LNG, a state-of-the-art liquefied natural gas receiving and regasification terminal located in Saint John, New Brunswick. The terminal is capable of sending 1.2 billion cubic feet of natural gas per day.
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