We are interested to hear your thoughts on which innovative vendors would be more interesting for you to find? You can simply respond by 1, 2, or 3.
In our research on innovations in artificial lift, the common comment we hear from E&P companies is, “These pumps fail frequently and are not optimized.” One’s first instinct might be to solve the immediate problem which is:
1. OPTIMIZE THE PUMP
Some innovators once aware of the failure points of these pumps, such as gas locking, erosion or pump degradation by solids, corrosion, power quality issues, etc. have tackled these problems head on. Gas management around ESPs, strength coatings on rod pumps or hybrid power solutions can reduce the frequency of failure. Many companies offering analytics and digital solutions are also providing well surveillance, failure prediction and automation of these pumps. Altogether, these solutions enable longer uptime and higher production from the well.
The curious minded have taken this line of questioning one step further. They strive to address the root cause as opposed to treating the symptoms of pump failures:
2. OPTIMIZE THE FLUIDS:
Movement of a multiphase fluid in the horizontal section of a well with an undulating trajectory is to a large extent unknown to us. Liquid settlement in the low points of the well trajectory or in the toe of the well could result in loss of production or slug flow that ends up killing ESPs for example. A group of innovators are working hard to find ways to understand this phenomenon. They are experimenting with managing the fluids to force single-phase flow in the well, change the flow regime of the fluids in the well or place the pumps further than the heel and into the horizontal section of the well. The intriguing fact is that by working on the root cause, some of these solutions can increase the reserves not just accelerate production.
The operators that work hand in hand with these innovators soon realize that they could solve these root causes not just by managing them, but by avoiding them in the first place:
3. OPTIMIZE THE WELL:
Dog-leg severity is a simple example of this. In an organization in which reducing the time to drill wells is the key performance indicator, no D&C team will increase drilling time and its accompanying expense in order to reduce the dog leg angle to allow easier deployment of pumps. In addition, many decisions on what type of lift systems to install on wells have often been a matter of preference by the production staff rather than a well-researched economic and technical assessment. In general, E&P companies will soon design wells to maximize production over their lifetime and not just for the first 18 months of production, which typically encompasses the initial natural flow period of the well and installation of the first artificial-lift system.
During periods of high commodity prices, the economic return of a new well in a shale-gas or tight-oil reservoir was so high that optimizing its production at the tail end of fast-declining initial production was at best an afterthought. Now that capital budgets have shrunk, many operators are going back and rethinking their approach to artificial lift.
For more information on our research visit us at www.darcypartners.com