Coiled tubing can play a major role in fracture-stimulating horizontal completions as described in several recent case histories.

Several horizontal stimulation treatments were recently performed in an oil field in southeast New Mexico. Horizontal openhole completions are relatively uncommon in the formation of interest and an economical means of stimulation was required. A tubing-conveyed fracture stimulation method using dynamic diversion was utilized to place six hydraulic fractures in each openhole horizontal wellbore using Halliburton's patented SurgiFrac fracturing service.

The first treatment was performed with a rig-assist snubbing unit. All six zones were fracture-treated in a single day.

The production response to the stimulation justified the economics of the operation, and the technique was applied on the next three completions. To expedite the treatment, coiled tubing was used in lieu of a rig. These coiled-tubing-conveyed treatments incurred significantly less downtime and eliminated the risks associated with underbalanced rig operations, resulting in faster, safer and more efficient operations.

How it works

The SurgiFrac process is the first known successful method to resolve the problem of openhole fracture placement control by using dynamic diversion techniques. Instead of using mechanical sealing or chemical blocks, the system uses the fluids' own dynamic movement to divert most of the energy into a specific point in the formation. The process is well suited for acidizing carbonate zones or using proppant-laden slurries to achieve fracture conductivity (Fig. 1).

Accurately placing fractures in horizontal wellbores and precisely controlling fracture initiation and propagation can help operators achieve the following goals:

• Increase production from existing assets. Re-enter openhole horizontal wellbores with coiled tubing or jointed pipe and create fractures precisely in bypassed or underperforming zones, quickly and cost effectively.
• Optimize reservoir drainage. Precise location of fractures means that treatments can be customized to meet well conditions.
• Add new production more quickly than with conventional fracturing. Multiple fractures can be created in the wellbore in only hours with no sealing (packers, etc.) required between zones.
• Reduce fracturing treatment costs. Low tortuosity inherent in the process can help cut costs by requiring less equipment and lower viscosity fluids.

To implement the process, a small jetting tool configured for the specific well being stimulated is placed on the end of the treating string. Coiled tubing can be used for applications when the necessary fluid rate for fracturing can be achieved. Because this process generates only one fracture system at a time, the required pumping rate is usually not extremely high. The tool is used initially to create a small-jetted cavity (tunnel) in the formation. The use of low sand concentrations in the jetting stage also allows the tool to perforate a liner or cemented casing. Once the fracture is initiated, an annular pressure surge is created that propagates the fracture out into the formation.

Fracturing horizontal completions pays off for operators

Until recently, the common belief was that horizontal completions usually eliminate the need for the hydraulic fracture stimulation that vertical completions normally require. Now we have learned that many horizontal completions may be less productive than fractured vertical wells. Often, low-permeability zones contain multiple layers of varying porosity and permeability. Unexpected vertical permeability barriers often exist that are too thin to be detected by conventional well logs. The SurgiFrac process has been applied successfully in a variety of fracturing conditions including the following:

• Multiple propped fractures in open hole
• Multiple acid fractures in open hole
• Deviated cased holes
• Horizontal slotted liners
• Coiled-tubing acid-frac to bypass damage
• Multiple fractures in a cased horizontal wellbore

Ten-Fold Production Increase

SE New Mexico: An old well in a mature waterflood was completed to a vertical depth of about 3,800 ft (1,158 m) with a 1,600-ft (488-m), 4.75-in.openhole lateral in a low-permeability carbonate reservoir. Cumulative production from the well was less than half that of most of its offsets. Production was only 3 BOPD when it was fracture-acidized using the SurgiFrac process. Eight distinct fractures were created at specified locations along the lateral. Acid for each stage was pumped through the treating string and then through 12 jets (3/16-in. diameter) at an approximate 5,000-psi pressure differential across the jets. Brine was simultaneously pumped through the annulus at rates required to maintain annular pressure at approximately 200 psi below the fracturing pressure. The tracer log generated following this treatment clearly showed significant amounts of tracer at all eight locations, as planned. A week after the treatment, the well was producing 50 BOPD (plus water) and was still pumping at 30 BOPD a month later.

Six-Fold Production Increase from "Slacker" Well

Canada: To stimulate production from three wells with horizontal completions in a low-perm carbonate reservoir an operator performed conventional treatments as well as the SurgiFrac process. The three wells of interest ranged in depth from approximately 11,000 ft to 12,500 ft (3,354 m to 3,811 m) and contained laterals ranging in length from 2,200 ft to 4,600 ft (670 m to 1,402 m). Reservoir pressures ranged from 3,219 to 4,650 psi. Wells 1 and 2 had the best potential and were treated using coiled tubing and a tool with a jetting sub to place acid treatments. Production increases were disappointing.

Well 3 had the lowest prestimulation production rate, even though it had the longest openhole lateral of the three wells. It clearly had the poorest production potential, and after Well 2 experienced such short-lived increase in production, the operator felt that the only hope to make Well 3 economically viable was to create deep fractures that could connect with natural fracture networks that were not near the borehole.
The treatment was performed with 1.75-in. coiled tubing. The operator pumped three stages averaging approximately 5,000 gal. of gelled 28% HCl acid down the tubing through the special SurgiFrac service tool. By pumping CO2 through the annulus, foam was formed downhole that enhanced acid retardation and helped limit fluid loss, enabling the creation of longer fractures. Although only three fractures were placed along the lateral, production increased by more than 600% (from 0.83 MMscf/D to 5.9 MMscf/D). The well exhibited a slower decline than Well 2, indicating that the treatment was successful in reaching the far-field fracture network. By using SurgiFrac technology, the operator turned the poorest candidate of these three wells into the best producer in this low-permeability reservoir.

Openhole multilateral level I wells

Texas and Louisiana: The SurgiFrac process has been used to create 6 to 14 independent fractures in each of several dual and triple lateral wells. Some of the wells were sand fractured and others were acid fractured. Initially, the operator was concerned that the fluid losses caused by the additional laterals would reduce the effectiveness of the technology. However, the consistent excellent production rates achieved prove that if permeabilities are not too high, the process can be used to stimulate wells that were previously untouchable using conventional approaches.

Offshore, openhole horizontal well with pre-perforated liner

Offshore Brazil: Three proppant fractures were placed using bauxite and resin-coated bauxite (16-20 mesh) in concentrations reaching 14 lb/gal. During the final portion of each fracture, instantaneous tip screenout was started successfully by proper modification of the annulus rate. After the SurgiFrac process, production increased five-fold.

Fracture distribution problem solved

Although it is clear that openhole completions can be hydraulically fractured using proppant or fracture-acidizing, the greatest challenges are in finding ways to achieve adequate stimulation results. Uncontrolled generation of hydraulically induced fractures normally will result in fractures being poorly distributed along an openhole lateral of any length.

For optimum production enhancement, a fracturing-stimulation program should result in a limited number of discrete fractures that are widely separated and well distributed along the lateral. If too many fractures are propagated, the width and length of each are reduced as the number increases.

The other primary objective is to create fractures where they are needed, and only where they are needed. Multiple fractures in close proximity to each other will improve the initial stimulation response but usually provide little additional cumulative production beyond the first year or two following the treatment.
A high-rate, large-volume openhole fracturing stimulation attempt, where fluid is simply bullheaded into the open hole, typically results in extreme multiple fracturing that causes most of the treating fluid to be placed in one small area near the heel section, leaving the rest of the interval essentially untreated. This result is typical when the lateral has very homogeneous formation properties and no zones are fractured during the drilling process. Even when the horizontal wellbore is almost aligned with the fracture plane, uncontrolled fracture creation usually results rather than an evenly spaced, effective arrangement. When the wellbore is exactly aligned with the fracture plane, one small longitudinal fracture will occur.

In some instances, operators have shot perforations at selected intervals to enhance the distribution of fractures down the lateral but this has produced only very limited success. In most cases, fracture distribution may appear slightly improved over that achieved with the bullheading technique, but ultimately the fracture distribution will not stimulate the reservoir sufficiently for a cost-effective completion.
The process of running a tubing string a long distance into the wellbore, then fracturing down the tubing (at a limited rate) or down both the tubing and the annulus simultaneously (at a high rate) has been used but has not achieved a high success rate in most areas.

Multilateral horizontal completions

A growing number of marginally economic Level 1 and Level 2 multilateral completions are providing marginal to poor economic results. Many of these appear to need stimulation, either to get beyond wellbore damage or to overcome vertical permeability barriers. Conventional stimulation technology is usually inadequate without some type of mechanical isolation technique. Conventional methods with a good chance of effective stimulation are usually either too high a risk for well problems or too costly to consider for low-return reservoir conditions (or both). Using a system of controlled, precisely placed fractures conveyed by coiled tubing can turn many marginal wells into excellent producers, and do so cost-effectively.