Page 395 - Fundamentals of Gas Shale Reservoirs

PRODUCTION PHASE DISCUSSION 375
job does not have to be shut down between stages, because 17.5.12 Fracturing Considerations for Completion
the frac balls can be dropped while the fluid is being pumped. Method
The total time of the fracturing process is dependent on the • The cost of services required for the completion must
frac plan, but in some instances 40 stages have been frac- be considered for the operator’s economic concerns.
tured in only 24 h with a ball‐activated system. The ball
seats, however, do create an ID restriction. In most scenarios • Availability of services and supplies must be
(as shale wells tend to be low flow rate) this is not an issue considered.
unless a screenout occurs. Therefore, this technique may not • If there is a shortage of frac fluids or proppants, how
be the best choice during the appraisal phase. Once operators much of a benefit is nonstop fracturing?
reach the development phase and are more familiar with the • The size and type of completion directly affects the
formation/reservoir, screenouts are less likely to happen. fracturing operation parameters including fracture ID,
Ball‐activated systems can help drive efficiency during the pump rates, slurry concentrations, pressure ratings, and
fracturing process, and allows for wells to come on produc- a number of other factors.
tion faster than with plug‐and‐perf (Burton, 2013).
Coil tubing activated systems offer accuracy and
contingency options during the frac process. The frac main- 17.6 PRODUCTION PHASE DISCUSSION
tains efficiency, requiring only brief shutdowns between
stages to move the coiled tubing assembly to the next stage. The production phase includes (i) monitoring/optimizing
Shutting down the fracturing allows for the most accurate production; (ii) managing the complete water cycle; (iii)
fluid placement into each stage, which is significant in for- reducing corrosion, scaling, and bacterial contamination in
mations where over displacement of fluids is an issue. Also, wells and facilities; (iv) installing artificial lift if required;
the coiled tubing is already in the wellbore. If a screenout and (v) protecting the environment.
occurs, this would keep nonproductive time to a minimum.
This system can actually allow a more aggressive frac 17.6.1 Monitor and Optimize Producing
design. The frac is performed through the annulus of the Rates—Current Practice
coiled tubing and the liner string; therefore, the fracturing ID
is significantly reduced. This completion system is dependent Managing and controlling well flowback rates are the first
on coiled tubing; therefore, depth and availability of coiled steps in optimizing production and ultimate recovery. Many
tubing at the same time as a pressure pumping crew can operators open wells on full choke in order to obtain
result in limitations on this type of completion. Because the maximum production rates immediately. This may possibly
coil tubing–activated system uses frac sleeves, the placement be an acceptable practice for shale oil wells, but not for shale
of the stage cannot be adjusted on the fly. If there were ample gas wells.
data to determine the placement of the stage before the well
is completed, this system would be a viable option during 17.6.2 Monitor and Optimize Producing
the appraisal phase. Primarily, because the system offers the Rates—Recommended Practices
flexibility, should a screenout occur. If additional data gath-
ering that could impact the placement of the stages is per- Multistage hydraulically fractured wells require a poststimu-
formed after the completion is set, this may be a better option lation flow period to prepare the well for long‐term produc-
for completion optimization during the development phase tion. This is one of the most critical times in life of well, more
(Burton, 2013). so for shale gas wells as opposed to tight gas wells and shale
oil wells. Excessive flowback rates are known to have caused
17.5.11 Drilling Considerations for Completion proppant flowback or fracture collapse. Intensive management
Methods of flowback can yield significant improvement in well’s long‐
term performance (Crafton, 2010; Crafton and Gunderson,
• The quality and gauge of the wellbore affects which 2007). An operator in the Haynesville reported in 2010 that
type of completion can reach the intended depth and “Haynesville wells … have been produced using restricted
whether or not cement or open‐hole packers are rate production practices. Additionally, initial decline rates
required to achieve isolation for all stages of the well. appear more gradual as a result of restricting production.”
• If deviation exceeds 15°/100 ft, it is recommended to This operator also stated that the decline curves modeled
run a torque and drag simulation to determine if the higher EURs from the restricted well rates. It appears that this
completion will physically go in the wellbore. is one instance of a technique that could slow down the
• A reamer run is recommended if there is a small dramatic initial decline rates characteristic of shale gas wells.
clearance between the wellbore ID and the completion Total production from a multistage hydraulically frac-
tool OD. tured well can be monitored, but there has not been a truly