Normalization of Analog Horizontal Wells for Type Curve Generation in Tight Gas Plays
- Shaoyong Yu (ConocoPhillips Canada Ltd) | Jim Gouveia (Rose & Associates Ltd)
- Document ID
- Society of Petroleum Engineers
- SPE/CSUR Unconventional Resources Conference, 20-22 October, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2015. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.7 Reserves Evaluation, 5.7.2 Recovery Factors, 4.6 Natural Gas, 1.6.6 Directional Drilling, 5.8.1 Tight Gas, 5.8 Unconventional and Complex Reservoirs, 1.6 Drilling Operations, 5 Reservoir Desciption & Dynamics
- Dry/Wet Gas Play, Type Curve Generation, Normalization to Analog Wells
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A mature reservoir is usually characterized with a number of both vertical and horizontal wells, which may both contribute to a significant recovery to-date. When considering forecasting for new wells in the geological similar areas (GSAs), it is common practice to generate a type curve by harnessing historical production data from analog wells. But, given varying well types and completion practices (e.g. different horizontal wellbore length), the analog assumption may be challenged.
When working on type curve generation, the common questions frequently asked are:
Do we need to normalize analog wells for the type curve generation?
How to conduct the normalization on both wellbore length and completion parameters?
It seems that the answer to the first question is a very obvious yes if the new wells will be designed differently from the analog wells – particularly if the lateral length and completion method is not similar. As a result, Estimated Ultimate Recoveries (EURs) and the Initial Production (IPs) will need to be normalized from those analog wells to a desired new wellbore length.
After having investigated both analytically and numerically the impacts on Recovery Factors (RFs) and the IPs from those factors of horizontal wells that include horizontal wellbore length (L), fracturing spacing/stages (nf) and drainage area (A), or well spacing, it is found that:
RF will be directly affected by the wellbore length. There is linearity between RF and L when the latter is less than a certain value. The fracturing spacing/stages and drainage area (well spacing), however, will affect RF when the reservoir matrix permeability is extremely low.
Also, IP has a high positive correlation with lateral length. In fact, these two variables have high linearity. In addition, fracture spacing will have a large impact on IP rates; however, drainage area will not at all. Note that these conclusions presume that wellbore hydraulic considerations are not a constraint. Further, lateral length presumes an effectively stimulated horizontal section.
The specific scope of this study is to provide a systematic normalization technique. Dry gas and wet gas case studies from the Western Canadian Sedimentary Basin (WCSB) have been adopted to demonstrate the workflow. Further, sequential accumulation statistical logic has been successfully applied to validate the premise of lateral length and fracture spacing as the key normalization variables.
It is believed that this methodology is rigorous for dry and wet gas reservoir systems. Moreover, this methodology is also applicable to richer gas-condensate and oil plays; however, broader relationships need to be established and tested before any conclusions can be drawn with wellbore hydraulic dynamics being taking into account as an effective factor.
|File Size||4 MB||Number of Pages||22|
Furui, K., Zhu, D., and Hill, A.D. 2003. A Rigorous Formation Damage Skin Factor and Reservoir Inflow Model for a Horizontal Well. SPEPF 18(3): 151-157, SPE-84964-PA. DOI:10.2118/84964-PA.