Tag Archives: Well Failure

Bring It On Sooner & Keep It Lifting Longer. Solutions To Consider For ESPs (Or Any Field Equipment)

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Settled on average 6,000 feet below the surface, electrical submersible pumps (a.k.a ESPs) provide artificial lift for liquid hydrocarbons for more than 130,000 wells worldwide.
Installing the correct ESP system for the well, installing it precisely, and careful monitoring of the system is paramount to reducing the risk of a premature end to an ESP life cycle. But the increasingly long laterals of horizontal wells, along with rapid drilling in remote areas, is creating challenges for efficient operations and the ESP’s life span. Implementing the correct processes and data strategies will, undoubtedly, be the cheapest and fastest way to overcome some of the challenges.

1- Implement A Process Flow That Works, Break The Barriers

When a decision is made to install an ESP in a well, a series of actions are triggered: preparing specifications, arranging for power, ordering equipment, scheduling operations, testing, and finally installing it in a well, to state a few. These actions and decisions involve individuals from multiple departments within an organization as well as external vendors and contractors. These series of actions form a process flow that is sometimes inefficient and is drawn out, causing delays in producing revenue. In addition, sometimes processes fall short causing premature pump failures that interrupt production and raise operational costs.
Research of many industry processes shows communication challenges are one of the root causes for delays, according to LMA Consulting Group Inc. Furthermore, communication challenges increase exponentially when actions change hands and departments. A good workflow will cut across departmental barriers to focus on the ultimate goal of making sure Engineering, Procurement, Logistics, accounting, vendors, contractors and field operations all are on the same page and have a simple and direct means to communicate effectively. But more importantly, the workflow will allow for the team to share the same level of urgency and keep stakeholders well informed with the correct information about their projects. If you are still relying on phones, papers and emails to communicate, look for workflow technology that will bring all parties on one page.

A well-thought through workflow coupled with fit-for-purpose technology and data is critical, not only to ensure consistent successful results each time but also to minimize delays in revenue.

2- ESP Rented Or Purchased, It Does Not Matter… QA/QC Should Be Part Of Your Process

Although ESPs are rented and the vendor will switch out non-performing ones, ensuring that the right ESP is being installed for a well should be an important step of the operator’s process and procedures. Skipping this step means operators will incur the cost of shut downs and tempering of reservoir conditions that may otherwise be stabilized – not to mention exposure to risks each time a well is penetrated.
More importantly a thoughtful workflow ensures a safe and optimal life span for ESPs regardless of the engineers or vendors involved, especially in this age of a mass retiring of knowledge.

At today’s oil prices, interrupted production for a well of 1,000 barrels per day will cost an operator at least $250,000 of delayed revenue for a 5 day operation. Predictive and prescriptive analytics in addition to efficient processes can keep the interruption to the minimum if not delay it altogether.

3- Know Why And How It Failed Then Improve Your Processes – You Need The Data And The Knowledge

One last point in this blog: Because ESPs consist of several components, a motor, a pump, a cable, elastomer, etc… ESP failure can, therefore, be electrical, mechanical, thermal or fluid/gas composition. Capturing and understanding the reasons for a failure in a system to allow for effective data analysis provides insight that can be carried forward to future wells and to monitoring systems. Integrating this knowledge into systems such as predictive analysis or even prescriptive analytic to guide new engineers will have an effect on operator’s bottom-line. A few vendors in the market offer these kind of technology, weaving the right technology, data and processes to work in synergy is where the future is.

On how to implement these solutions please contact our team at info@certisinc.com.

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What More Can Be Done To Reduce Well Failure & Downtime? Predictive Analytics.

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Today’s high oil prices make every production moment crucial and well downtime costlier than ever. When a well fails, money sits underneath the earth’s surface, but you cannot get to it. In addition, you have equipment and a crew draining money out of your pocket while you wait to replace a critical component. Ideally, you wouldn’t wait. You would be ready for equipment failure.

Example: One operator reported that downtimes causing an average of 400 bbl per day of production loss is normal practice. If we assume a minimum margin of $50 per bbl, that is more than $7 Million dollars of uncaptured revenue in that year. That’s a hefty price tag. Oil companies need to ask themselves: “what more can be done. Have all measures been taken to keep downtime to its minimum?”

With high equipment costs, companies used to balk at owning spare equipment. On the contrary, some companies consider backups as standard procedures. The trick is deciding on a balance between stockpiling backups and knowing what you really need ahead of time. I believe this balance can be achieved with “Automated Predictive Analytics”.

Predictive analytics compares incoming data from the field to expected or understood behaviors and trends to predict the future. It encompasses a variety of techniques from statistics, modeling and data mining that analyze current and historical facts to make future predictions.

Automated predictive analytics leverages systems to sift through large amount of data and alert for issues.  Automating predictive analytics means you can monitor and address ALL equipment on the critical path on a daily basis–more frequently if your data permits. Automating steps up the productivity of your engineers by minimizing the need to search for problem wells. Instead, your engineers can focus on addressing problem wells.

If you are not already on the predictive mode, these two cost-effective solutions can get you started on the right path.

1. Collect well and facility failure data (including causes of failure data). Technology, processes and the right training make this happen. There are a few tools available off-the-shelf. You may already have them in house; activate their use.

2.  Integrate systems and data then automate the analysis: expected well models, trends and thresholds need to be integrated with actual daily data flowing in from the field. “Workflow” automation tools on the market can exceed your expectations when it comes to integration and automating some of the analysis.

Example: One operator in North Dakota reported that 22 of its 150 producing wells in the Bakken have failed within the first two years due to severe scaling in the pump and production tubing. Analytics correlated rate and timing of failure with transient alkalinity spikes in the water analyses. The cause was attributed to fracturing-fluid flowback. (Journal of Petroleum Technology, March 2012).

In the above example, changes in production and pressure data would trigger the need to check water composition that could in turn trigger an action on engineers to check the level of scale inhibitors used on the well before the pump fails. This kind of analysis requires data (and systems) integration.

One more point on well failure systems. Too many equipment failures occur without proper knowledge on what went wrong. The rush to get the well producing again discourages what is sometimes seen as “low priority research”. Yet, this research could prevent future disruptions. By bringing the data together and using it to its full potential companies can save money now and for years to come.