Yu S.,ConocoPhillips |
Gouveia J.,Rose and Associates Ltd.
Society of Petroleum Engineers - SPE/CSUR Unconventional Resources Conference | Year: 2015
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: 1. Do we need to normalize analog wells for the type curve generation? 2. 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: A. 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. B. 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 demon strate 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. Copyright 2015, Society of Petroleum Engineers.
Dobson M.L.,Chesapeake Energy Co. |
Lupardus P.D.,Chesapeake Energy Co. |
Divine T.W.,Chesapeake Energy Co. |
McLane M.A.,Rose and Associates LLC
Society of Petroleum Engineers - SPE Americas Unconventional Gas Conference 2011, UGC 2011 | Year: 2011
A practical probabilistic method is presented to administer the evaluation of proved undeveloped (PUD) oil and gas reserves in resource plays. In 2009, the Security and Exchange Commission (SEC) adopted revisions to the oil and gas reporting rules which allowed for the opportunity to use probabilistic methods in the evaluation and disclosure of PUD locations that are more than one spacing unit away from existing production. The revisions to the "Modernized SEC Rules" created a need for improved methods to evaluate and disclose probabilistic reserves. The objective of this paper is to present a new and practical probabilistic method for PUD reserve reporting that addresses the SEC requirements. The paper addresses the issues of proved reserve volumes per PUD location, proved well spacing, and "sweet-spots". The useful method may be applicable to a broad range of subjects, such as professional expertise, individual ownership positions, and geologic play situations. The figures and principle steps of the method are presented using the Fayetteville Shale as an example. The method was developed specifically to comply with the Modernized Rules, to be consistent with statistical principles, and to accommodate ownership situations while maintaining an expectation of being practical to use. The first paper (Dobson 2011) in this series of three introduced a new method of describing the proved area in a resource play. The third paper will present a practical justification for this probabilistic approach. In this paper, historical production statistics are used to evaluate the method's ability to comply with reasonable certainty in a forecast at specific PUD locations. Copyright 2011, Society of Petroleum Engineers.