November 2019

Greater transparency would benefit users of type curves in unconventional formations

Improved disclosure of how type curves are created in shale basins will increase user understanding of the quality and reliability of these estimates, to make better-informed decisions.
Steve Hendrickson / Ralph E. Davis Associates, an Opportune LLP company

Unconventional reservoirs present challenging problems for reservoir engineers trying to predict the future performance of undrilled and recently completed wells. In conventional reservoirs, there are many analytical techniques that can be used, but unconventional reservoirs present too many complexities, variations and unknowns to apply these methods. In particular, the extent, geometry and conductivity of the fracture network is unknown and perhaps impossible to model.

A common solution is to use production data from existing wells as analog for future wells to generate a “type well profile” (TWP). TWPs, also called “type curves” are derived by selecting analog wells, collecting their production history and key well information, and applying several mathematical adjustments to generate the prediction. The adjustments include steps like estimating the future production of existing wells; normalizing the data to the first month of production; scaling the data to account for differences in lateral length or fracture design; and binning the data according to other parameters, such as formation or operator. The scaled and normalized production can be used to generate average production forecasts for each of the bins.

Operators use TWPs to make investment decisions, prepare reserve estimates, and to inform their investors about the expected economics of their undrilled wells. Many of them are disclosed to the public in investor presentations and public filings. Although they are widely used, typically there is very little disclosure about how they are derived. There are no industry standards for the preparation of TWPs. Rather, they are created under many different circumstances and engineers have personal opinions about the best way to prepare them. Some of these opinions are certainly better than others.

The development of best practices for TWP generation is currently under consideration by a committee of the Society of Petroleum Evaluation Engineers. Ahead of that work, however, the engineers at Ralph E. Davis Associates believe that improved disclosure about how a TWP was created would help users better understand the quality and reliability of the estimate. It also would provide more transparency to help them understand why different engineers in the same play and area might generate different TWPs.

Fig. 1. Sample of type well profile, Delaware basin, lower Bone Spring (oil).
Fig. 1. Sample of type well profile, Delaware basin, lower Bone Spring (oil).

Recommendations for better TWP disclosure. We recommend that TWPs presented to the public, or to other consumers, be accompanied by a voluntary disclosure that explains or addresses the following items. Sample disclosures are provided below, Fig. 1.

Selection of analogous wells – A list of API numbers, and a map or a description of the area that includes the analogous wells. If certain well types, operators, vintages, etc. were used to filter the list of wells, that should be disclosed. If the list of API numbers is not disclosed, the number of wells used should be disclosed for each TWP. The goal is to make it clear which wells were used and why.

Source of production data – Describe whether the data came from internal or public sources and cite the source. If lease-level data have been allocated to individual wells, that should be disclosed.

Frequency of production data – Describe whether daily or monthly production was used. Some public data are reported quarterly, so if the monthly data are calculated from quarterly values, that should be disclosed.

Months of production history used – The disclosure should discuss how many months of production data were available and used in the TWP. One approach would be to provide the minimum, maximum and median number of producing months.

Scaling and binning – How were the production data for each analog well scaled to account for variations in relevant variables (lateral length, for instance) and how were the analogs binned to generate the TWPs?

Project the average or average the projections? – Petroleum engineers may average the analog wells’ normalized historical data and then project the average into the future; or they may project the future performance of the analogs and then average the wells’ combined history/projection data. If projections were used, what engineering methods were used to make them? Engineers that have access to detailed production and pressure history data will sometimes employ additional reservoir engineering techniques to project the analog wells before aggregating them.

Form of TWP equation – What form of production rate versus time equation (Arps, etc) is used to represent the type well?

TWP parameters – What are the relevant parameters of the resulting TWP? For example, initial rate, initial effective decline, b-factor, minimum decline, final rate, well life and expected ultimate recovery.

Reliability measures – Statistical measures should be presented that allow the user to understand the uncertainty and reliability of the TWP. These could include confidence intervals around the TWP or standard deviation as a function of time (absolute or a percentage of the expected value).


There are many approaches to creating TWPs, and they often rely on very limited data. We believe that their users should have enough information to understand how they were made, so they can make informed decisions. A thorough disclosure of the data and methods used would be a good first step. 

About the Authors
Steve Hendrickson
Ralph E. Davis Associates, an Opportune LLP company
Steve Hendrickson is president of Ralph E. Davis Associates, an Opportune LLP company. He has 30 years of professional leadership experience in the energy industry, with a proven track record of adding value through acquisitions, development and operations. In addition, he possesses extensive knowledge in petroleum economics, energy finance, reserves reporting and data management, and has expertise in reservoir engineering, production engineering and technical evaluations. Prior to joining Opportune, Mr. Hendrickson was principal of Hendrickson Engineering LLC, which was focused on reserves assessment and property valuation supporting property acquisitions and corporate restructurings. He began his career at Shell Oil as an engineer in Permian basin waterfloods and CO2 floods. Since then, he has focused on leading upstream oil and gas reserves evaluation/engineering projects, serving in management at several E&P companies, including El Paso Production, Montierra Minerals & Production and Eagle Rock Energy Partners. Mr. Hendrickson is a licensed professional engineer in the state of Texas and holds an MS degree in finance from the University of Houston and a BS degree in chemical engineering from the University of Texas at Austin. He also serves as a board member of the Society of Petroleum Evaluation Engineers.
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