Successful delivery of oil and gas development projects are measured against the promise of an expected production outcome, delivered safely within a scheduled time and budget. This promise is generally based on production forecasts and cost/schedule estimates, with the aim to incorporate the impact of risks and uncertainties on the project. While there are established methodologies for incorporating uncertainties into production forecasts and risks into cost and schedule estimates, there is no established methodology for quantifying the impact of subsurface, drilling or operational risks on production forecasts within foreseen range of cost and schedule. As a result, these risks are often either ignored or incorrectly accounted for as an arbitrary percentage discount on forecasted volume. The objective of this paper is to propose a clear methodology to categorize, quantify and incorporate these risks in forecasts, provide a basis for robust production forecasting and drive better business decisions.

Three main risk types are defined in this methodology under two categories: Execution risks and Operational risks. Execution risks are defined as the risks occurring at the time of execution comprising of Subsurface and Mechanical risk types. Subsurface risk is probability that the encountered subsurface outcome is poorer than considered in the uncertainty ranges, e.g. depleted, swept, compartmentalized or with unexpected fluids/contaminants. Mechanical risk is the probability of unsuccessful drilling, completion or intervention of the well as per the development plan, e.g. due to borehole collapse, well loss or completion failure. Operational risks exist throughout the production lifetime and are defined as the probability of premature failure of the well or shut-down of the facility before producing its Estimated Ultimate Recovery (EUR), due to completion failure, well and facility integrity challenges.

The Execution risks are expressed as Chance of Success (CoS) against the risk and modelled using a Bernoulli distribution. The Operational risks are defined using a CoS and a distribution function derived based on statistics of historical failures observed in regional/analogous field(s). The risks are rolled-up in a probabilistic decision tree analysis along with the low, mid and high subsurface outcomes. The P90, P50 and P10 cases are identified from multiple realizations based on production rates and EUR outcomes, and deterministic equivalents of each outcome are selected based on possible scenarios.

The Development Well Risking methodology incorporates multiple risks into production forecasts, and introduces a more robust approach towards forecast adjustments across the industry. Furthermore, the methodology is used to better evaluate competitive scopes and assist with decision making processes. The risking also provides a basis for justification of base protection projects or activities that de-risk base case production but provide no direct incremental value/volumes, while require cost expenditure. The methodology can be implemented into integrated subsurface, surface and economic analysis workflows in evaluating Expected Monetary Value (EMV) to ensure an integrated outcome is achieved.

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