During the last several years our industry has developed innovative ways to efficiently drill and complete unconventional wells, from automated drilling rigs to pad drilling to zipper fracking and more. While this progress has lowered costs and created many advantages, there is still room to improve. The question remains—how can we maintain efficiency but also improve effectiveness? About 40% of horizontal frack stages contribute to 80% of the production. This means we are leaving behind billions of dollars in unproduced reserves and spending millions of dollars fracking stages that do not provide a return on investment (ROI). Every so often it takes a diversion like our current downturn to refocus, change our approach and invest in the innovation that our industry and the world economy rely on.
Historically, many of our industry’s best ideas are born during the down periods. This downturn will be no different. We must take advantage of our resources and time to review the performance of our fields and determine how we can improve the effectiveness of our completions.
While operators wait for commodity prices to improve and for service companies to bring pricing in line, horizontal rig count is down significantly and completions are being deferred. At the same time that activity is drastically declining, operators are holding on to the best and brightest personnel, knowing that people are a huge asset in our still-developing industry. This is the perfect storm for putting those bright minds to work by reviewing current fields, better understanding frack techniques and determining what contributes the highest and lowest ROIs. Now is the time to take a hard look at data that were gathered when things were going and blowing to glean more information that can be used to improve production from underperforming fields and also to optimize all wells going forward. This can include reprocessing data and creating statistical models for better prediction, evaluating which wells are prime refrack opportunities and using new technologies to develop fields moving from sweet spot to peripheral locations. Instead of relying on old methods to model, complete and evaluate frack jobs, operators can use this time to develop (or work with technology companies to develop) models and processes that are fit-for-purpose for unconventional completions.
The first opportunity that comes to mind is developing an improved frack model that takes into account the realities of unconventional shales, one that uses actual data like microseismic as a constraint. In boom times, operators were more apt to stick to their completions plans for efficiency’s sake rather than make changes in real time that can, at times, completely turn around the economics of a well. With improved technologies and a cultural shift toward optimization, we are slowly seeing operators take advantage of the data and information that are available real-time.
Finally, we are still using conventional reservoir models to develop projections for unconventional wells. The economics of our industry are built on these models, and newer, more appropriate solutions are in the works that use microseismic and other data to determine permeability and EUR.
In this activity slowdown, technology companies and service companies also have the capacity to build into the wave of the future. If operators and service companies can partner together to develop, test and iterate on new technology, our industry will emerge from this downturn stronger and more profitable than ever. The real opportunity in front of us is in increasing recoverable reserves from 5% to more than 10% at similar cost levels. A move like that would generate significant value for our companies, investors and communities. Now is the time to invest in that value and move our focus from efficiency to effectiveness, something we like to call Frack 2.0.
The deal would create the largest pure-play northern Midland Basin E&P with a 73,000-net-acre position and 12,000 boe/d of production that is expected to more than double through 2020.
The French major aims to drill 23 wells this year, its senior vice president for exploration, Kevin McLachlan, told Reuters, in waters off Mauritania, Senegal, Namibia, South Africa, Guyana and Brazil.
Repsol will still hold a 51% stake in the block after the deal.