Created by the Institute for Energy Technology in Norway in 1979, Olga was the oil and gas industry’s first transient multiphase flow model. A source of national pride, the program has been declared one of the country’s most important innovations in recent decades. Transient models simulate what may happen to a production system over any given length of time, be it minutes, days, or years. This allows operators to plan for events, such as shutdowns and restarts, for nearly the whole life of an offshore facility. Olga is also used in engineering design, operator training, and real-time production monitoring.
Dag Biberg, a Schlumberger advisor who works on the Olga modeling program, estimated the model has been used on thousands of pipelines and offshore wells. Olga is credited as a key enabler for the economic development of many fields, including the Shell-operated Ormen Lange subsea gas field, where the wellstream is transported over uneven and steeply inclined terrain by two pipelines to an onshore processing facility in Norway.
Biberg said the development of Olga, acquired by Schlumberger in 2012, has come through many small steps spanning decades of research and development. “Only occasionally do we have real step changes,” he said.
One example, he said, occurred more than 20 years ago when the technology advanced from modeling two phases (oil and water combined, plus gas) to being able to model all three phases of the production stream. Another crucial leap forward for offshore operators, which happened about 20 years ago and continues to be developed, was slug tracking. This allows operators to simulate what would happen to their production systems as the slugs of gas and liquid move through their system.
Modeling technology for managing liquid slugs in gas condensate pipelines is especially critical. When these liquid buildups occur and move through a pipeline, operators rely on large tanks known as slug catchers located at the receiving end of the pipeline. By using a transient model such as Olga, operators can simulate these liquid slugs or surges over a given period of time during pigging of the pipeline or increases in production to prevent a separator to be operated without flooding the slug catcher.
“Our most recent step change is the introduction of the high-definition stratified flow model,” said Biberg. He explained that this latest advancement allows engineers and operators to use the improved predictions associated with a 3D flow description without suffering a serious penalty in execution time.
Schlumberger has also launched an initiative to meld its modeling technologies into a single stream, whereby engineers can look at how fluids move from the reservoir all the way through the end of the production system to identify a host of potential problems as early as possible.
Every once in a while, developers will find discrepancies between what Olga predicts and the field and lab data. To fix these problems, they launched the Olga Verification and Improvement Project (OVIP), which Schlumberger said often leads to improvements in the model’s reliability. Several major oil companies have partnered to form OVIP and many of the investigations are decided by a vote between those member companies.
Currently, the joint venture group is focusing on gas condensate flows and liquid accumulation points and Schlumberger said the work has already yielded improvements in Olga.
Among the improvements accomplished through OVIP are
- Gas/condensate pipelines (1998–1999 and 2007–2008)
- Heavy oil slug flow (1998 and 2009–2012)
- Slug lengths and frequencies (1999–2003)
- Pressure drop in slug flow (1999–2003)
- Oil and water holdups in three-phase slug flow (2000)
- Downward inclined flow (2001–2002)
- Vertical annular flow (2002–2003)
- Riser slugs (2002–2006)
- Slug flow correlations (2007–2009)
- Oil and water accumulation in gravity-dominated flows (2010–2012)
