In a not-yet-published survey, research analyst firm CERA has found that “integrated production-system models” are today being applied in at least 3% of global liquids production in the petroleum industry. Judson Jacobs, director, upstream technology, says CERA believes this is “just the tip of the iceberg” in terms of the contribution these models can make toward helping maximize oil & gas field production. The key to greater use and benefit from an integrated model, said Jacobs, is that it be “fit for purpose,” and support decision making such that the effort of maintaining the model is justified in the eyes of those charged with its use. Integrated production-system models — also referred to as “integrated asset models” or “integrated production models” — typically combine reservoir model and simulator; well models; and surface-network model in a single higher-level model. The integrated model may have its own optimization engine. For true operations support, actual production data will be fed into the optimizer from a data historian. By these means, analysis and what-if scenarios can be applied across an entire asset. Integrated models are actually quite prevalent in the petroleum industry, said Jacobs. However, the many instances in which such models are used for weekly or monthly planning purposes — as opposed to true on-going operations support — were not included in the CERA survey results. Neither was evidence of growing use of integrated models in gas fields included in the survey. Benefits of integrated production-system models are based on having greater understanding of the complex interactions across a petroleum reservoir, surface facilities, and, in some cases, even its supply chain and refinery networks. “Today, the most common uses of integrated models are associated with large artificial-lift systems, and maximizing overall field production,” Jacobs said. Another important, growing use is flow assurance in subsea environments. Operators are most likely to support integrated models when they deliver answers to something more concrete than vague promises of overall optimization. “They are most effective in addressing a specific challenge or opportunity,” said Jacobs. “For example, say a company’s goal is to maintain plateau production of an offshore gas asset. Yet drilling additional wells increases water cut across already-producing wells. A better understanding across the full suite of wells can be attained by means of the integrated model.” In the process and refining industries, use of integrated models is quite common, said Jacobs. “Refining is a margin business and anything that increases efficiency to incrementally increase those margins is quickly embraced. We’re seeing some of those same pressures being brought to bear in the upstream sector.” Yet several factors inhibit greater use of integrated models upstream. “While there are some technical challenges in integrating reservoir simulators, what’s inhibiting greater use of integrated models isn’t the technology,” said Jacobs. “The model should serve as a common language for interaction. But production engineers and facility engineers don’t always share the same incentives. The challenge is to align the organization so that the model is maintained and its recommendations heeded.” Yet the single greatest challenge to greater use of integrated production-management models in today’s petroleum fields may be answering the asset manager’s simple question, “If I don’t use it, will this field still produce oil tomorrow?”
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