Big Fracs That Add More Oil May Also Mean More Water, and That Can Be All Right

Abstract

A few years ago, Occidental Petroleum managers were puzzled by why their recent Permian Basin wells were producing more water per barrel of oil, so they asked some engineers to figure out what was wrong. Their concern was understandable. While the company’s well evaluation system was supposed to screen out prospects likely to become big water producers, the amount of water flowing out of wells in the Delaware Basin drilled after 2018 far exceeded volumes from previous years. “We found that newer wells had a steeper increase in water cut over time than older wells,” the coauthors of an Occidental paper wrote about the work done to answer the question. They added, that “pre-2018 wells had an average water cut increase of 4% in the first 300 days (after cleanup) and then stayed relatively flat after 300 days, whereas post-2018 wells’ water cut increased at an average of 12% in the first 300 days and 16% in the first 600 days before reaching a plateau” (URTeC 3720245). Those trends, plus wells ultimately reaching an 80% water cut, suggested that a string of wells may have been drilled into water aquifers. While that is a risk in the Permian, the evidence suggests that the geology in the wells they compared was similar before and after 2018, even though the water cut levels were not. A big difference was how the wells were fractured. In 2018 Occidental began doing bigger fracturing jobs, using more water and sand per foot, which increased the number of stages and fracturing clusters. Those changes added oil production because “high conductivity speeds production and enhances the well’s net present value,” said Samuel Amadi, a senior reservoir engineering advisor for Occidental, while presenting the paper at the recent Unconventional Resources Technology Conference (URTeC). Based on production records, the water/oil ratio also was higher. Using data from comparable wells before and after the completion design changes, a model was created that quantified the relationships between fracturing designs and the oil, water, and natural gas flowing out of Occidental wells. “One recurring observation in all these completion scenarios is that a better-completed well will have higher fluid withdrawal and a steeper water cut trend after cleanup than a poorly completed well for the same reservoir and operating conditions,” the paper’s authors wrote. A coauthor, Xueying Xie, principal and manager of unconventional recovery design at Occidental, added that based on her team’s simulations, “we know we are not doing something wrong. This is doing a better job. It speeds production.” But unlike a well drilled through a fault connecting it to an aquifer, there was a limit to the water produced from these extremely tight formations. Like the oil production in more aggressively completed wells, the water production peaked at a higher level than the less intensely fractured wells but declined over time to a similar level. “On the water production side, just the pace changes,” Xie said.