Assessing Production Forecast Accuracy: A West Africa Field Case History

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166317, "Assessing the Accuracy of a Production Forecast: West Africa Field Case History," by Anna Apanel, SPE, Robert Tester, SPE, and Brodie Thomson, ExxonMobil Production Company; and Ginga Mateus, SPE, and Gaspar Marques, SPE, Esso Exploration Angola, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

The subject field is in the deep water off West Africa. Over its 7-year life, the field reached a peak production of 90,000 BOPD and produced nearly 100 million bbl of oil from a high-quality stacked Lower Miocene deepwater channel complex. This field provides an opportunity to perform a review of how well the reservoir-performance predictions made at project funding matched with the final actual field performance.

Introduction

The production forecast developed at project funding did a very accurate job of predicting average reservoir behavior such as most likely ultimate recovery and production plateau. However, a more detailed comparison of the preproduction depletion plan and the actual field performance shows significant differences. In particular, both gas and water breakthrough and buildup were faster than expected. These factors were offset by higher well productivity and larger in-place oil volumes. 4D seismic acquired after 3 years of production was particularly effective in illuminating gas and water flow pathways in the reservoir that had not been modeled or predicted. In addition, changes were made to the original depletion plan to increase recovery and in reaction to operational issues. The factors that drove the evolution in the depletion plan are reviewed and an assessment is made on the accuracy of the original production forecast.

Production Forecast Evaluation Criteria

A reappraisal of a production forecast involves three important steps: (1) comparing actual asset performance with predictions at funding, (2) identifying the model assumptions that are materially different from actual performance, and (3) performing a root-cause analysis to understand why these assumptions were made and what could have been done differently. Estimated ultimate recovery (EUR) is often quoted as the key metric, but it is important to look at all of the components of a reservoir evaluation to understand why there were differences.

A typical project oil production profile can be broken down into three components that are critical to project economics. The buildup phase refers to the initial production ramp-up with development drilling and is affected by the initial well rate and number of wells online. The plateau phase refers to the period of steady production after the peak rate is achieved. The plateau rate is typically driven by facilities design capacities. The duration is typically driven by hydraulic limits as wells lose pressure or are affected by encroaching water or gas production. Finally, the decline phase begins when the production drops from plateau and continues to abandonment or contract expiry.