Artificial lift

Guest Editorial: Managing Production to Weather the Storm

The recent plunge in oil prices has reinforced a number of truths about our industry.

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The recent plunge in oil prices has reinforced a number of truths about our industry.

  • It is cyclical.
  • Declining prices shift spending from capital expense to operating expense models.
  • In depressed markets, operators turn their focus to high-value return on existing assets that meet the price threshold.
  • Operators who successfully harvest production from those existing assets are well-positioned for the inevitable market upturn.

While the advent of US unconventional plays has created nothing short of a seismic shift in our industry, these truths at least remain constant. And they all point to one fundamental certainty: In a “bust” cycle, production is king. It pays the bills. It helps keep the wheels of technology innovation turning. It is the foundation on which the next “boom” is built.
The challenge, however, is in the approach to and execution of production enrichment programs.

Balancing short- and long-term value from a producing asset depends on a long list of variables related to wellbore construction, fluid content, and oil composition. None of these variables exist in isolation. It takes a coordinated, planned approach to production if you want to reduce lifting costs, maximize productivity, and improve cash flow. But too often, planning for the production phase does not happen early enough in the life of a well.

From the Beginning

Like the smart little pig who built his house of bricks to withstand the wolf’s huffing and puffing, an optimum production management solution begins with initial well construction decisions. Factors such as depth, casing diameter, liner diameter, deviation, and length of the lateral can affect how the well is produced. The most effective production management strategies help operators reap the benefits of better drilling efficiencies and open up more of the reservoir to the wellbore without limiting artificial lift options over the life of the well. That is a tall order when you consider that drilling teams rarely consult production engineers before a well is drilled.

Wellbore geometry, particularly in shale plays and other horizontal drilling and hydraulic fracturing operations, can be quite challenging for artificial lift. We have what I will call a space/time conundrum when it comes to production from unconventional wells. Are we drilling wells that have enough space to allow for the maximum production and reserves recovery over time? Unfortunately, too often the answer is no.

For example, tight curve sections in horizontal wellbores are, in some cases, planned to save drilling costs and open additional pay zone to the wellbore, but this strategy has traditionally limited artificial lift options.

The good news is that technology innovation is keeping up. A new electrical submersible pumping (ESP) system design was recently introduced that makes it possible for ESPs to be installed through deviations of up to 25°/100 ft, which meets or exceeds the capabilities of the industry’s best currently available directional drilling systems. But it is difficult to stay ahead of the game with production technology innovations when drilling efficiency always wins the day.

And the wellbore is not the only issue. The production stream itself presents a host of challenges. Sustained production requires a deep understanding of the produced fluid in not only changing production rates over the decline curve, but also the chemical composition of the oil, the oil/water ratio, the gas/liquid ratio, and the solids content and type. All unconventional wells produce some gas, causing performance deterioration because of gas blocking and locking in the production system. These effects can usually be resolved with special pump and intake designs as well as gas separators.

However, another gas phenomenon called slugging, which is common in long-lateral horizontal wells, is much harder to resolve. Wells are characterized by high and low points along the lateral section. Over time, gas collects in the peaks and creates slugs, which then move up the well, entirely displacing the fluid. Clearly, for pumping systems designed to pump fluid, that is a problem. If the duration of the slug is brief, there are ways to keep the ESP systems operating. If the slug is of a longer duration, it can shut down the unit, thus increasing downtime and potential equipment failure, both of which result in increased lifting costs.

Again, technology is winning the day. Thanks to innovations such as sophisticated gas control software that can be installed as part of a monitoring and optimization service package, service providers are finding ways to overcome the production challenges inherent in unconventional wells.

Need for Integrated Production Management

One synergy that seems obvious, but too often is overlooked, is an integrated artificial lift and production chemical solution. The composition of the oil itself presents challenges such as viscosity, scale, paraffins, asphaltenes, and iron, hydrogen, or other sulfides that can create serious reliability issues in artificial lift and completion systems, and can clog flow paths, thus reducing production rates and cash flow.

Understanding how the issues created by the composition of the oil—and the chemicals used to treat those challenges—affect the artificial lift system can dramatically impact total lifting costs. Implementing technology piecemeal not only drives up lifting costs, but also introduces long-term inefficiencies. Protecting the return on investment requires shifting production decisions to earlier in the asset development process and then designing flexible production management solutions that integrate the right mix of artificial lift, production chemicals, and production monitoring and optimization services to deliver the best outcomes for the specific needs of each well and each operator.

This approach requires an integrated, collaborative team with the domain expertise to understand how all the pieces of the puzzle work together to ensure flow assurance, equipment integrity, and production optimization over the life of the well.

Flexible Terms

A technical solution, no matter how good it might be, is only effective if it meets an operator’s business and financial goals. It is a fundamental business principle that can often get lost in the “technical” nature of our business.

A flexible commercial approach is as important as the technology solution when it comes to integrated production management, particularly in unconventional plays in which economic drivers differ substantially from conventional plays as well as from unconventional basin to basin, and from operator to operator. Commercial models can be customized for an operator’s specific needs, but some require an integrated approach to the production system for the model to work.

For instance, no fault, fixed period leases are possible if monitoring and control capabilities are part of the production solution. Likewise, when artificial lift and production chemicals are integrated, warranties can be expanded to cover downhole conditions, a service that could not be offered if the same service company does not manage both the artificial lift and chemical treatment programs.

As mentioned earlier, operators who successfully leverage production from their existing assets will weather the current market downturn more effectively and emerge from it with a significant competitive edge. An integrated, collaborative approach to production management will help drive down lifting costs and improve cash flow today while protecting the long-term viability of the reservoir and the wellbore.

At the end of the day, it is about working together to focus on the drivers that will sustain both our business and our ability to continue to provide affordable energy to the world’s populations.

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Wade Welborn is vice president of artificial lift systems for Baker Hughes. Before assuming his current role, he served as the managing director of the Nigeria geomarket. He has more than 23 years of engineering and management experience in the oilfield services industry. He began his career with the Western Company as a field engineer in 1991 and joined Baker Hughes 4 years later and has held positions of increasing responsibility during his tenure with the company. Welborn holds a BS degree in petroleum engineering from Texas A&M University and an MBA from Robert Gordon University in Aberdeen.