Refrac Challenges


Conventional Refracturing

Refracturing vertical wells has been a successful proposition for decades. This results from a variety of reasons.

  • The conductivity of the initial fracture stimulation degrades continually from the first day of production. This is due to issues related to proppant embedment, fines migration, scale and paraffin precipitation and relative permeability effects.
  • Stress re-orientation in the reservoir due to production can result in the re-fracture operation contacting reservoir rock not previously accessed. Obviously, it's easier to isolate zones of interest in a wellbore not already containing hundreds of existing perforation shots. Success requires some homogeneous, bypassed rock that can be accessed through various re-perforating, diverting, or isolation methodologies.

 

Candidate selection is of utmost importance in predicting economic success. If skin damage is the only obstacle, the incremental response is easier to predict than if a full-force hydraulic refracture is required. In this case, reservoir pressure and stress changes will have to be incorporated into a 3D simulation, as well as improved fluid and proppant utilization, concerning both qualities and quantities. But there is more than tangible incremental production at risk. There is also the intangible operational risk associated with downgraded pressure limitations with all existent wellbore conduits (tubing, casing and wellhead).


Unconventional Refracturing

Refracturing horizontal wellbores in unconventional plays, with their heterogeneous lithology, is even more complex. There are the myriad of perforation schemes and holes to work with, so you have to understand how the original wells were completed, such as plug and perf vs. sliding sleeves, fluid type, proppant volumes, and stage spacing. The huge issue is isolation and diversion when faced with a 5,000 - 10,000 ft lateral that may have thousands of perforations, or worse, open sliding sleeves in an uncemented lateral. Ball sealers, sand slugs and degradable diverter schemes recommended by some service companies are delivering limited success straddling packers on stick pipe or coild tubing can serve to isolate sections of the wellbore.

Do you leverage the existing perforations and induce larger fracs with higher quality of fluids/proppants, or recomplete previous lateral sections that were probably bypassed on original fracs due to well or frac stage spacing? Or both? Were these laterals originally cemented? If so, it's possible to re-perforate in between original stage spacing, isolate that zone and re-fracture, or use coil tubing to simulate all three. Regardless, the effects of stress shadowing/profiling will be evident, as well as reservoir pressure changes. Monitoring adajacent wells for possible interference is also important. Again, candidate selection is critical to the economic success of the program.

One of the biggest obstacles in re-fracturing horizontals is predicting economic success prior to the actual operation. Many operators don't believe 3D simulators have advanced to the point wherein they can accurately model these heterogeneous reservoirs, so how can they predict associated production increases? Dynamic geomechanical modeling tied to microseismic and seismic attributes, followed by reservoir simulation can deliver these answers.


SIGMA³ Delivers a Distinct Advantage

SIGMA³ helps clients improve field performance by delivering practical recommendations and completion techniques that improve the production response from both existing and new completions. Using a comprehensive engineering approach field-tested in basins around the world, production comparisons are conducted to evaluate different completion techniques, and production responses are reviewed on each well to verify the impact of hydraulic fracturing modeling results.