Ever since hydraulic fracturing was introduced shortly after World War II, the industry has relied on multistage fracturing to help maximize asset value. Selectively stimulating individual intervals in the wellbore can help hold down operating costs, reduce time to initiation of production and improve ultimate recovery.

In fact, one of the first experimental fracture treatments on record is reported to have been a four-stage pinpoint stimulation job in 1947 in the Kansas portion of the Hugoton field, which targeted four limestone gas pays at depths ranging from 2,340 to 2,580 feet. That stimulation job was conducted in four separate hydraulic fracturing treatments (stages), each of which involved pumping 1,000 gallons (gal) of napalm (thickened gasoline) through jointed tubing equipped with a cup-type straddle packer, followed by 2,000 gal of gasoline with 1 percent gel breaker.

Selectively fracturing individual zones with a series of treatments was the only option possible at the time because of the equipment limitations. The available equipment was not capable of pumping the high rates, volumes and pressures necessary to stimulate large sections of the wellbore.

That began to change in the 1950s, as the introduction of better casing and tubular products, more powerful pumps, and more capable wellsite equipment combined to enable operators to reach deeper, larger oil- and gas-bearing strata. By the mid-1960s, the primary method used to stimulate gas wells in the Hugoton field was to hydraulically fracture long sections of the wellbore-frequently encompassing several intervals in a single treatment-by pumping large volumes of low-cost water-base fluids at very high rates. This reflected an industry-wide trend toward large, high-volume fracture treatments targeting several intervals in the wellbore and away from strategies allowing the selective treatment of individual intervals in a well.

Selectively fracturing multiple zones
Despite the acceptable levels of success and reliability achieved over several decades by "stimulate everything" approaches to hydraulic fracturing, chronic shortcomings persisted. The overriding limitation in most instances boiled down to the inability to design a single, large fracture treatment that could take into account all the significant, variable characteristics of both the targeted potential pay zones and interbedded nonproductive zones.

Including interbedded geologic zones of doubtful value in the segment of wellbore to be fractured inevitably increases treatment costs and can significantly escalate the risk that the treatment will not perform up to expectations. In general, experience has shown that selectively stimulating individual pay zones while avoiding interbedded intervals can help hold down treatment costs and enhance treatment performance by helping ensure fracturing fluids are diverted into the targeted intervals.

While true in most instances, effectively fracturing individual pays can be costly and time consuming. In addition, many of the solutions developed to reduce the cost and time required to stimulate multiple intervals-such as sand-plug diversion, drillable bridge plugs, retrievable packers, limited-entry perforating, or perforating with explosives-in some cases reduced overall stimulation effectiveness by introducing new complexities to the treatment process.

The ability to pinpoint individual geologic zones for stimulation really began to come of age with the introduction of coiled tubing (CT), which enabled two paradigm-shifting capabilities. Perforating and fracturing bottomhole assemblies (BHAs) mounted on a string of CT could be inserted into the well and moved under pressure into any positions desired, saving considerable time by eliminating the need to break and remake connections in order to initiate some steps in the treatment process or to move to another zone. In addition, CT enabled perforating and fracturing treatments to be conducted in live well conditions, significantly improving the results and reliability of multizone treatments.

However, the need to pump treatment fluids at high rates to achieve the fluid volumes, velocities and downhole pressures required for perforating and fracturing mandated that early CT-based methods of pinpoint stimulation use large diameter coiled tubing such as 2-3/8 or 2-7/8 inches. Large-diameter CT limited the depth to which selective stimulation of multiple zones was feasible because of the additional weight as well as the footage limits imposed by the reel capacity of conventional CT units.

Leveraging lessons of the past
The increasing maturity of the U.S. oil and gas resource base is heightening the need to find and test ever-smaller accumulations of hydrocarbons, and the increasing sophistication and effectiveness of modern exploration and drilling technologies are gradually making that possible

As the industry's leading stimulation company, Halliburton embraces the responsibility to develop and commercialize new, more effective wellsite technologies that can help meet the increasing demand for energy, despite the dwindling domestic resource base. As part of that commitment, the company began rethinking the performance capabilities of the many stimulation tools and methods developed by the oil and gas industry in the past six decades. The objective was to assess each existing stimulation technology and seek ways of combining the best available capabilities into a new stimulation technique capable of setting a new level of multizone stimulation efficiency and effectiveness.

 One result of Halliburton's research is the CobraMax^SM fracturing service, which allows the selective, pinpoint placement of multiple customized, hydraulic fractures in unperforated, cased, vertical wells. The CobraMax process integrates six existing, proven well-stimulation technologies-depth correlation with CT, Hydra-Jet™ tool perforating, Hydra-Jet tool fracture initiation, hydraulic fracture stimulation, achieving isolation by proppant packing the annulus across the just-fractured zone, and casing clean-out using CT-into a unique process that can enable the selective perforation and fracturing of multiple zones in a single trip into the wellbore.

In the CobraMax process, perforation and fracture-initiation fluids are pumped through the CT string to the Hydra-Jet BHA and the fracturing treatment is pumped down the casing annulus, providing the high performance capability of conventional through-tubing fracturing with the speed and versatility of CT. Importantly, this combination allows the use of smaller OD CT pipe, as small as 1-3/4 inches. Smaller CT pipe allows for treatments inside of casing as small as 3-1/2 inches. Plus, it allows for deeper multizone stimulation treatments due to increased CT pipe lengths on the surface reels.

Overview of CobraMax service benefits
The CobraMax process can help optimize such key stimulation treatment parameters as fluid injection rates, proppant volumes and proppant concentration, ensuring that each prospective pay zone is custom-stimulated.

By using the new single-entry stimulation technology, producers can perforate and fracture multiple pay zones quickly and cost effectively, including intervals requiring larger, higher rate treatments that could not have been achieved by older CT-based stimulation methods, or zones too deep to have been reached using large-diameter CT.

The ability to custom-stimulate individual productive horizons in a single trip to the well site can help maximize asset value by increasing the efficiency and effectiveness of stimulation efforts, reducing cycle time to production, and lowering unit production costs. In addition to enabling perforating and fracturing to be performed in the same trip downhole, the CobraMax process incorporates no downhole packers or bridge plugs that must be manipulated; and it eliminates the need to set mechanical plugs that must be removed later.

Using the casing annulus as the main flow path for fracturing fluids allows injection rates to be achieved that in the past were possible only with conventional through-tubing stimulation. Perforating and initiating fractures through CT allows treatments to be placed at much lower rates, freeing annulus fracturing pressures from the high-differential jetting pressures and submitting targeted intervals to less extreme pressure dynamics.

In one application, the CobraMax process was used to successfully place more than 2.2 million pounds of proppant into 17 discrete zones in a single treatment. Production after load recovery increased 120 percent, compared to two offset wells stimulated in five stages using bridge plugs and limited-entry fracturing.

The CobraMax service process
The CobraMax process is initiated by inserting the Hydra-Jet BHA at the end of a CT string into the wellbore and positioning it at the deepest targeted zone. The perforation process is initiated by pumping a fluid containing a dense abrasive material through the Hydra-Jet tool nozzles. Within a few minutes, the high-velocity abrasive fluid jetting through the nozzles erodes 1/2-inch to 1-inch holes through the casing wall and cement sheath and cuts tunnel-shaped cavities-or perforations-several inches into the surrounding formation rock.

Perforations created with Hydra-Jet tool technology typically exhibit very high levels of connectivity with the wellbore. The alternative, explosive perforating, can create compaction zones around the perforation tunnels that can impede the entry of fluid into the fractures.

After the perforations are created, annulus pressure is increased to initiate fractures in each of the perforations.

Proppant packing and casing clean-out
After fractures have been initiated, a specified volume of proppant-laden fluid is pumped through the casing annulus to the fractured interval. As the proppant begins entering the perforations and moving under high pressure through the fractures, the pumping rate on the CT is reduced to allow the CT to provide a method of monitoring bottomhole pressure changes during the fracture treatment. A predetermined increase in bottomhole pressure after the final proppant stage reaches the perforations indicates a proppant pack has been properly placed in the annulus across the perforations. This pack will serve as the isolation mechanism for subsequent treatments up hole.

Once the proppant pack is observed, low-rate pumping continues through the CT but ceases down the annulus, and the Hydra-Jet BHA immediately is pulled to the next zone to be perforated and fractured. Pumping through the CT then ceases and excess proppant is reverse-circulated out of the hole through the CT. The hydrajetting/fracturing sequence is repeated for the next interval.

Once all stimulation targets have been treated, excess proppant is cleaned out of the casing, either by immediately reversing through the CT while traveling to total depth (TD) or by returning to the surface and changing to Hydra-Jet BHA with a wash tip before tripping to TD.

If all costs associated with conventionally perforating and fracturing a well are taken into account, the CobraMax process typically is more economical to perform in any situation involving four zones or more. When CobraMax service is combined with the benefits of high performance fracturing fluids like SilverStim® service and exclusive conductivity endurance technology including SandWedge® enhancer and Expedite® services, the results can be very beneficial in helping operators improve their profitability.