Technology Update
Efficient production in many fields requires reservoir stimulation. Some of the challenges with hydraulic fracture stimulation are reservoir-related, such as consistently stimulating all targeted intervals. The growth of hydraulic fractures in the vertical direction is difficult to predict, leading to the risk for entering unsought gas- or water-bearing formations. Operations can be complex, costly, and pose environmental challenges.
A new liner-based stimulation technology has been developed and field tested by Fishbones to be simple, efficient, and more controllable with less environmental impact. The method uses less fluid and reduces greatly the risk of groundwater contamination and the disposal of recovered stimulation fluid. Field experience has shown positive productivity response, with an 8.3 times increase in 30-day cumulative initial production (IP-30) in an existing well in a tight limestone formation. The productivity index was increased by 30 times.
The liner-based stimulation technology was originally developed for carbonate reservoirs, but is also applicable in coalbed methane and unconsolidated formations. Technology suitable for sandstones and other clastic formations is being developed.
Technology Description
The technology uses a liner sub that houses four small-diameter, high-strength tubes called needles, each with a jet nozzle on the end (Fig. 1). The sub is made up to a full-length casing joint and needle assemblies up to 40 ft long are assembled in the workshop before the sub is sent to the field.
The subs are run as integral parts of the liner in the open hole and are positioned across the formation where stimulation is desired. The needles are located inside the sub/liner joints while the sub is run in hole. The liner is hung off with a standard liner hanger.
In a carbonate formation, a basic hydrochloric acid (HCl) fluid system is pumped. The fluid jets out of the nozzles, and the formation ahead of the tubes is jetted away by a combination of erosion and acid chemical dissolution. Differential pressure across the liner drives the needles into the formation, and they penetrate the rock until fully extended. Typical jetting pressure is 3,000 psi.
All laterals are created simultaneously in a short pumping job, resulting in a fishbone-style well completion with multiple laterals extending from the main bore (Fig. 2). The rate of penetration depends on the formation composition, porosity, downhole temperatures, nozzle configuration, jetting fluid, and jetting pressures. The needles exit the sub at an approximate 40° angle. The bending through the exit port results in laterals with an approximate 90° angle relative to the wellbore.
