Liner-Based Stimulation Technology Without Fracturing Proven in Field
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.
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.
The needles may be equipped with a positive identification mechanism that shuts off the flow when a needle is fully extended. This will give a pressure indication on surface that jetting is completed.
A fit-for-purpose float shoe enables circulation during the run in hole, but closes upon contact with the acid, thus providing a closed-pressure system for jetting.
Depending on the length of the horizontal wellbore, downhole temperatures, and the number of laterals, a number of openhole anchors are positioned in the liner to eliminate axial liner movement during jetting. An anchor with 330,000 lbf anchoring capability in washed-out holes has been developed and qualified.
The jetting and dissolution of the carbonate formation create lateral tunnels of ½-in. to ¾-in. in diameter or larger. The oil will predominantly flow in the lateral/needle annuli and into the main bore, where it will flow through production valves in the subs, into the production liner, and up the well. Each sub has two production valves phased 180° apart. These valves do not allow outward flow during the well operation, but enable inflow during production.
Connecting the Reservoir
The purpose of the technology is to increase well productivity, or injectivity in the case of injection wells, by better connecting the reservoir to the wellbore. The technology is applicable in low-permeability formations to create a negative skin similar to the hydraulic fracturing process for reservoirs that are
- Compartmentalized, layered, or naturally fractured.
- Without barriers to contain hydraulic fractures.
- Depleted, where placement of hydraulic fractures is challenging.
- With insufficient depth accuracy for sweet spot well placement.
Damage to the formation rock near the wellbore is bypassed. But the analysis of post-job pressure data shows that the majority of the stimulation can occur more than 10 ft from the wellbore. The length of the laterals is adjustable by tailoring the tube lengths. This means that the depth of the stimulation is controllable. Thus, the risk of penetrating untargeted zones is eliminated.
The installation of the system is similar to an openhole liner installation and uses a standard drilling or workover rig. Zonal isolation is not required, but swellable packers can be used if a zone needs to be isolated. No ball dropping or pipe manipulation is needed to activate lateral jetting. The fluids are bullheaded after the liner hanger is set.
The technology requires less rig time and shorter pressure pumping operations than hydraulic fracturing, while using a fraction of the chemical volumes needed for fracturing, using no explosives, and eliminating elevated work above the rig floor.
The stimulation technology was recently used in existing producing horizontal oil well in the Austin Chalk formation in Texas. The installation of the system was part of a pilot program managed by the Joint Chalk Research (JCR) group composed of BP, Shell, ConocoPhillips, the Danish North Sea Fund, Dong, Eni, Hess, Maersk, Statoil, and Total. A goal of the JCR is to improve recovery from the chalk reservoirs on the Norwegian and Danish continental shelves. The pilot installation was also supported by the Norwegian Research Council.
The operator of the pilot well had experienced consistent challenges with prior stimulation both with running in hole with fracturing assemblies and achieving zonal isolation and proper diversion. The pilot well, horizontally placed in a tight limestone formation with approximately 5% porosity, was shut in after 3 years of production and prior stimulation and was considered to be without potential for normal restimulation. A 4.5-in.-diameter lower completion string was planned for the 6.5-in.-diameter open hole. Fifteen subs with a total of 60 needles and three openhole anchors were spaced out with 4.5-in.-diameter liner joints.
Half of the needles were equipped with the positive pressure verification mechanism for identification of fully extended needles. The acid-activated float shoe was run in the toe of the string. The shoe had a tungsten carbide cutting structure to facilitate reaming the liner in the hole, based on previous operator experience of unstable wellbores in Austin Chalk re-entries.
The stimulation completion was deployed on drillpipe with a workover rig. When the shoe reached the 7⅝-in. casing shoe, string rotation was started as per standard workover procedure. The completion string was rotated at 40 rev/min for more than 10 hours to total depth with a typical 2,500 ft-lbf of torque, with spikes up to 7,000 ft‑lbf. The liner hanger was set and the packer integrity checked before acid was pumped.
A basic inhibited 15% HCl blend was pumped to close the shoe and for the jetting operation. Jetting testing on core samples from an offset well provided by the operator before the installation showed that approximately 810 bbl of acid would be needed for the full extension of 60 tubes with 40-ft length.
During the pumping, a steep decrease in pump pressure at constant rate verified increasing injectivity. After 875 bbl of acid was pumped (within 8% of expected volume), a rapid pressure increase was seen at the surface, confirming full extension of the -needles. Additional acid was pumped to maximize the stimulation. An analysis of the post-job pressure chart indicated that all the needles had fully penetrated.
The pumping operation was completed after 5 hours, including jetting and fluid displacement. The creation of as many as 60 laterals in one well is believed to be a world record.
The well was completed with a beam pump following the completion and put on production. As of May, the well had been flowing for 30 days post-stimulation. In addition to showing an 8.3 times increase in IP-30 compared with well production before shut-in, the initial results showed a 2.6 times increase compared with IP after the well’s original completion. The results confirm the significant stimulation of the well by the use of the liner-based technology.
Liner-Based Stimulation Technology Without Fracturing Proven in Field
Thomas Jorgensen, SPE, Fishbones
01 July 2014
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