A new completion system allows multiple zones to be sequentially perforated and individually stimulated without any tools inside the casing string. The system has been field-tested in several North American gas wells with significant savings in time and money, as well as improvements in well productivity.

Marathon Oil Co. conducted detailed analyses of previous multizone completions and the related well performance.
Those studies showed productive layers of a completion were not being uniformly stimulated by conventional methods when more than one interval was completed in a single stimulation stage. Tracer logs and production logs suggested techniques such as limited entry perforating and high injection rates for diversion were not as effective as envisioned. As a result, reserve recovery and productivity were not being maximized.
Further analysis indicated the biggest potential step-function change to minimize expenses would be to eliminate the need to conduct operations inside the casing. Marathon engineers and their development partners conceived a new technique and associated completion system to provide a solution.
The system is based on the principle of attaching the perforating guns and associated hardware such as firing heads, control lines, isolation valves and pressure recorders to the outside of the casing. The guns are spaced out to cover the desired completion intervals as the casing is run. Precise positioning of the string is achieved by correlation with a gamma ray log, assisted if necessary by an optional radioactive marker tag in a special plug in the assembly. Once the casing is correlated at depth, it is cemented in place using conventional cementing techniques, including the use of a wiper plug.
The perforating guns may be actuated hydraulically, via control lines strapped to the outside of the pipe when it is run, or electrically, using armored logging cable in place of the hydraulic lines. When the guns are hydraulically fired, individual zones can be completed in sequence by using a system of graduated shear pins in the pressure-actuated firing heads. Additional remote firing methods are under development. Perforations penetrate both formation and casing, and stimulation treatments can follow immediately.
Initial field testing and fine-tuning of the design concept was conducted in a 2,500ft well near Drumheller, Alberta, in August 1999. Four separate intervals were individually perforated and fracture stimulated in 3 hours. The test's success led to minor design changes to reduce manufacturing costs and improve assembly and running efficiency. Subsequently the technique was commercialized and introduced as the Excape Completion Process. Preliminary estimates indicate cost reductions of 15% to 20%, time savings of 60% and productivity increases of 15% in a 5-to-6 interval completion.
System features
Details of the Excape system are shown in Figure 1. Key features include:
• externally mounted hollow carrier perforating guns;
• an isolation device between each interval;
• externally mounted hydraulic control line or armored electrical cable to surface; and
• optional externally mounted downhole pressure gauges.
The first system was developed on 3½in. casing to be run in a 77/8in. borehole. Future systems are planned for 27/8in. casing (6 ¼in. hole) and 4½in. casing (8¾in. hole). The design incorporates a six-shot-per-foot perforating gun. The majority of the charges are phased at 90° over a 270° arc facing away from the casing to deeply penetrate the formation. At least three charges per zone are phased at 22.5° and aimed at the casing to establish limited entry communication with the production string. These charges are designed to shoot completely through the casing, creating at least a 0.3in. exit hole on the far side away from the guns. The low-debris gun system allows treatment fluids pumped down the casing to enter the formation through a variety of flow paths, including through the perforating gun. An advantage of using an expendable carrier cemented in place is that larger explosive loads can be used for deeper penetration of the formation. The risk of split carriers associated with high-explosive-load retrievable guns is not an issue.
The perforating guns are mounted in specially machined Y blocks that are an integral part of the casing, making the installation rugged and durable. Each Y block contains a special plug that can accommodate a radioactive marker tag to facilitate accurate depth correlation if desired. A single casing gun module can perforate intervals up to 21ft, and modules can be run in tandem to span greater intervals. Selective perforating of intervals can be accomplished hydraulically using a system of pressure-graduated shear pins in the firing heads, and electrically using polarity-sensitive switches on the detonators. Electrical detonation has not been field-tested. In the hydraulically actuated design, as each firing head is actuated, the control line below it is isolated. Should gun detonation perforate the control line, system integrity is maintained.
Isolation devices
4,000psi-rated ceramic flapper valves placed between each gun interval enable individual zone treatment.
Before perforating operations, each flapper is recessed behind a protection sleeve that allows conventional cementing operations including the use of wiper plugs. During the firing sequence, the sleeve shifts upward exposing the flapper, which snaps shut to isolate the production string beneath it. The flapper acts as a one-way check valve diverting treatment fluids out through the perforations into the formation as each successive interval is perforated and treated. The flapper also serves as a catcher preventing any treatment sand from falling into the previously treated zones beneath it.
When all intervals are completed and the well is flowed to unload treatment fluids, the flappers are forced open by the upwardly moving fluid. The pressure rating of the isolation device can be increased to at least 10,000psi with a change in flapper materials. Ceramic material is used because it can be subsequently broken with slickline tools if necessary.
External control lines
Early concerns were voiced about the ability of externally mounted control lines to survive the run-in operation. On the Alberta well, a Canadian company, Promore, brought its considerable experience in installing external pressure gauges to help the development team address the problem. In more than 80 wells, many of which were horizontal, Promore had developed techniques to protect hydraulic control lines during run-in. In addition to installing wraparound metal protectors across the casing couplings, Promore devised a stand-off using old 7/16in. armored logging cable run under tension alongside the ¼in. hydraulic control line. While effective, the technique of using wraparound tool-joint protectors proved time-consuming and costly. Accordingly, special grooved casing couplings were designed to accept the control line, and steel bands placed on either side held the line in place (Figure 2). The special couplings cost half as much as the metal protectors used in the prototype well, and the approach was used successfully on subsequent wells with a 65% reduction in running time.
An innovative feature of the uppermost firing head allows the hydraulic control line to communicate with the inside of the casing after the firing sequence is actuated. This allows the hydraulic control line to be used as a chemical injection line for surfactant foams; scale, corrosion or paraffin inhibitors; or as a bubble tube for downhole pressure monitoring over the life of the well. This feature is an added advantage to using hydraulically actuated guns.
Downhole pressure gauge
By using new armored logging cable as a standoff, the operator can install a permanent, externally mounted downhole pressure gauge. A modified Y block on the uppermost gun is used to accommodate the gauge and protect the electrical connection. Besides monitoring downhole pressure during production, the gauge can be used to monitor pressures during stimulation treatments. Field engineers suggest this information will reduce the potential for premature screen-outs.
Preliminary economic analysis indicates downhole gauges will quickly pay for themselves by eliminating the costs and risks associated with diagnostic wireline operations and pressure surveys over the life of the well. In case of an unscheduled event during production, pressure build-up data taken from the permanent monitor gauge can help in diagnosing the problem and designing a solution.
Field experience
As described earlier, the first casing-conveyed perforating completion involved four intervals up to 21ft long. Completion depths were 1,400ft, 1,750ft, 1,780 ft and 2,420ft. The completion used hydraulically actuated firing heads and included a permanent downhole pressure gauge and ceramic flapper isolation valves. The casing was reciprocated during pumping operations, and rigid body eccentric and concentric turbolizers were used to ensure uniform distribution of cement around the completion assembly. Gun depths were correlated by gamma ray log.
While the cement cured, the rig was moved off location and the well was jetted dry with nitrogen using a coiled tubing unit. This allowed the lower interval to be perforated underbalanced. A handheld hydraulic pump was used to test system integrity and fire the lowermost gun. The next day, the lower interval was fractured and each succeeding interval was sequentially perforated and fractured. Total treatment time for the four intervals was 3 hours with only a 20-minute interval between zones while the next gun was fired.
To evaluate the job, downhole pressures were displayed directly into the stimulation van, and the data suggested the flapper valves operated properly. Radioactive tracers were used to tag the treatment, and subsequent logs confirmed the treatment was uniform across the zone and there was no interzonal communication, thus verifying cement integrity. Well productivity is nearly twice that of 80 offset wells, credited largely to the use of the casing-conveyed perforating and treatment technique.
Following a thorough evaluation of the first job, significant improvements were made to the hardware to reduce manufacturing costs and assembly time 40%. Besides the previously mentioned grooved couplings, the flapper valves were redesigned to be concentric, and the lower gun guides were made to slip over and lock down instead of thread into place.
The second well using casing-conveyed perforating was completed for Marathon near Wamsutter, Wyo., in December 1999. Although equipment was on hand to complete six intervals, openhole logs only identified two potential zones of interest: the Main Almond sand at 9,650ft and the Upper Almond sand at 9,520ft. A design criterion of the system is the ability to configure the guns and run the completion string within 2 hours of determining the zones and intervals to be perforated from the openhole logs. This criterion has been easily met, but requires transporting enough equipment to the well site to handle the greatest-case scenario. In the Wyoming well, two hydraulically actuated perforating assemblies with a single flapper valve and downhole pressure and temperature gauges were run in 15 hours, a 65% reduction in running time. Completion proceeded without incident. The continuously recorded pressure and temperature data will be used to analyze and improve cementing design and techniques in the future.
Future considerations
Marathon believes considerable reductions in safety, environmental and operational risks will result from eliminating numerous in-the-well completion activities. Additionally, life-cycle costs will be reduced by having a monobore completion for remedial activities such as setting bridge plugs, casing patches and coiled tubing workovers. Stimulation contractors experience much greater efficiency by being able to stimulate all intervals in a single day, usually with less hydraulic horsepower required on location.
Multizone completion techniques can be implemented whereby the displacement fluid from one treatment can be used as the pad fluid for the next treatment. Perforating in high-strength acid is under consideration as a means to facilitate cleanup, and spotting of this acid can be accomplished in conjunction with displacement as outlined above.
Marathon plans to complete at least 20 wells this year using this new technology.