To offset the fluctuations in the cost of oil, the oil and gas industry looks for improved efficiencies in all parts of its production chain. Predictive analytics leverages the large volumes and variety of historical well data to find critical patterns to improve performance, reduce losses, enable operators to be more proactive in field operations, and reduce operational costs.
This article describes how sensor analytics and predictive maintenance helped to prioritize gas well intervention to reduce downhole freeze events and reduce remediation cost.
The Challenge
Natural gas wells have a propensity to “freeze” (or “shut-in” due to hydrate obstruction), especially during harsh winter months, losing or deferring gas production and incurring intervention costs to disperse the obstruction and/or install a downhole pump. Predicting when each natural gas well is at risk for freezing and when it is likely to need a downhole pump installed is a challenging problem, but knowing the risks in advance enables effective prevention.
The client engaged Elder Research to discover and communicate actionable insights about well production and propensity to freeze (or experience pump failure) based on well design, environmental conditions, well interventions, and other data gathered by the client. The goal was to use predictive maintenance to optimize intervention resources to reduce operational costs and natural gas deferrals.
The Solution
Over a terabyte of operational well data was harnessed to identify and predict well freeze events on about 1,700 wells. The sensor data was mostly from wellhead and separator tanks and included temperatures, pressures, tank levels, and flow rates. Also, operational reports of freeze events were provided, and records of well design, well environment, and production history played predictive roles in the models. The data was large, diverse, noisy, often erroneous, and incomplete. To improve model performance many rules were developed and applied to clean the data and impute estimated values when data feeds were down or unreliable. With input from the client key ratios that affect the well’s propensity to freeze within the next three months were calculated.
Elder Research modeled well freezing and the need for plunger pump installation to predict the impact of interventions on gas production volume. Several modeling algorithms — including decision trees, neural networks, regression, and ensembles of multiple techniques — were applied, tuned, and evaluated. Figure 1 shows the freeze model performance compared to random decisions while Figure 2 demonstrates the benefit of knowing when pump installation and activation should to be completed.
Figure 1. Freeze Model performance compared to random decisions
Using an Agile model building process, the insights about predictive relationships were reviewed on regular intervals with client subject matter experts. The team applied the predictive models to all wells with adequate data available and predicted which wells would improve production if an effective intervention were made. Custom data visualizations were designed to illustrate important relationships.
Figure 2. Total gas production deferrals (MSCF, or million standard cubic feet) versus recommended time to plunger installation date. The recommended time after start of well production is before the 50th percentile date. This demonstrates the benefit of knowing when pump installation and activation should to be completed. The required information is available within one month of start of production.
Results
The models were thoroughly vetted by the client using a blind validation process and revealed actionable insights about well production and freeze propensity. The Plunger Pump model produced useful and flexible maintenance predictions for optimizing the timing of plunger pump installation and was projected to reduce production deferrals by 15-20%. Testing of the Downhole Freeze model revealed that it had a 70% success rate. Its insight helped the client prioritize well interventions to reduce well freeze remediation costs, with projected savings of 600,000 MSCF (million standard cubic feet) in deferred gas volume annually.
