Considered approach improves hydraulic fracturing in horizontal open holes

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Sept. 21, 22	Adv Hydraulic Fracturing
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Oct. 25, 26	Essentials of Hydraulic Fracturing
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Nov. 2, 3	Essentials of Hydraulic Fracturing
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and Hart's E&P magazine

Tracer log after the fracturing treatment.

Fracturing open holes reduces the cost of well completions and allows earlier production. Innovations in horizontal fracturing have allowed large reservoir volumes to be reached and drained by creating multiple fractures in a single well through injection of several hundred thousand gallons of fluid carrying several hundred thousand pounds of proppant. It is now possible to complete and fracture horizontal wells open hole with savings in rig time, cementing and casing costs, reduced fracturing time and cost, and reduced time to production.

Working the plan

One of the key elements of successful exploitation of tight gas reservoirs is the ability to fracture wells according to plan and production requirements. Most plans call for placement of multiple transverse fractures at specific locations within the horizontal well. Given the low productivity of these wells, the ability to successfully create multiple fractures is of paramount importance.

A popular method of creating multiple fractures is to use frac ports and sliding sleeves. Openhole packers isolate different segments of the horizontal well. A sliding sleeve is placed between each packer pair and is opened by injecting a ball inside the borehole. During a typical treatment, the completion string is placed inside the well. The string includes frac ports and openhole packers spaced according to well requirements. Spacing between packers can be as high as several hundred feet. The packers are actuated by mechanical, hydraulic, or chemical mechanisms. To activate each sleeve, a properly sized ball is pumped with the fracturing fluid inside the well. The ball size is smaller than the opening of all of the previous sleeves, but larger than the opening of the sleeve it is intended to open. Seating of the ball exerts pressure at the end of the sliding sleeve assembly, causing it to slide and open the frac ports. Once the port is opened, fluid is diverted into the openhole space outside the completion assembly, causing the formation to fracture.

At the completion of each fracturing stage, the next larger sized ball is injected into the well, which opens the next sleeve, and so on, until all of the sleeves are opened and multiple fractures are created in the well.

The main advantage of this completion technique is the speed of operations, which also reduces costs.

Overcoming failures

There are occasions when equipment does not function as planned, and treatment results are sub-optimal. In one treatment, nine fracturing stages were carried out over a two-day period using ball sizes of 1.25, 1.5, 1.75, 2.00, 2.25, 2.50, 2.75, and 3.00 in. During the treatment, the proppant was tagged with three radioactive tracers.

Examining the log from this project leads to several observations:

• The openhole packers did not keep the fracture contained. Fluid and proppant moved between some of the isolated intervals;

• Some of the sliding sleeves did not function properly, so some intervals were not fractured at all; and

• The fractures created were axial (longitudinal) and not dominantly transverse, as intended.

Analyzing tool breakdown

A look at the treatment chart for one of these treatments indicates the frac ball seating did not cause the typical sharp pressure increase. In fact, the pressure rise just before 425 minutes appears to have resulted from rapid rate increase.

The frac ball sizes in this treatment changed in 0.25-in. increments. Since the ball had to clear the previous sleeve (which has a 0.25-in. larger opening), the difference between the ball diameter size and sleeve seat opening is 1?8 in., or a radius difference of 1?16. Since the ball is plastic and the seat is made of steel, they have different elastic and thermal expansion constants and respond differently to pressure and temperature changes. The ball having just been pumped is likely to be at surface temperature, while the seat temperature can be warmer, depending on the time lag between the two injections.

Assuming that the ball in this example was injected at 9.2 bbl/minute, it was traveling with a velocity of over 15 ft/sec. With a small tolerance, the ball could have gone through the seat or could have shattered upon high velocity impact with the tubing wall or the seat. Whichever the cause, there is ample evidence to indicate that some balls did not seat to move the sliding sleeve and open the port.

Another possibility in this situation is that the wrong sized ball was released at the surface and seated at an earlier sleeve, leaving several downstream intervals untreated. Once this happens, the downstream intervals are inaccessible for subsequent injections.

Several actions can reduce the risk of failure in such cases:

1. Larger ball size increments could be selected. A 0.5-in. separation between ball sizes would have increased the chance of success on this job.

2. Lower injection rates could be used while seating the balls to reduce the chance of a ball breaking down and lessen the chance of the ball passing through the seat because of its high velocity.

3. An automated ball release mechanism could be used to control the sequence. Although automated systems are slightly more expensive, the reduced risk of failure makes them attractive.

The tracer log shows fracture propagation across the packers, which could be the result of several mechanisms:

• Axial (longitudinal) fracture initiation and propagation. The natural tendency of hydraulic fractures in horizontal wells is to initiate axially (longitudinally). Re-orientation of these fractures to become transverse is a gradual and random process. The treatment chart for this job shows that the initial fracture was dominantly axial and continued to grow for a considerable amount of time. Even at the end of the treatment, the fracture had a considerable nontransverse component. The fracture could have crossed the packed-off interval, aided in this process by the pressure exerted on the formation by the packer itself.

• Packer setting. If the packer is not set properly, the packer itself can fracture the formation.

• Wellbore condition at packer location. If the well bore is not reasonably round where the packer is seated, a gap can exist between parts of the wellbore perimeter and the packer, which allows fluid and proppant to move across.

General considerations

Proper operation of openhole fracturing systems requires attention to several wellbore environmental considerations.

At the time of installation, downhole tools are exposed to bottomhole temperatures. During fracturing and in the upstream flow, fluid injection gradually cools down these tools until they eventually reach surface temperature. Reduction in temperature causes the downhole tools and tubing string to shrink. For example, if the packed-off interval is 250 ft (76 m) long, a reduction of 100ºF (70º surface vs. 170º downhole) in tubing temperature causes shrinkage of almost 2 in. in the steel string within the packed off interval. Shrinkage imposes stresses on both packers and the connected shell of the steel string (some parts of the tool string, such as the inner sleeve parts, are not rigidly connected to the total string and are free to shrink). Shrinkage can impose additional frictional resistance between moving parts and hamper their free movement or increase the force needed to move the parts.

Horizontal wells generally are not perfectly straight or horizontal. Even minor bends and twists in the well trajectory, if they occur at critical locations with respect to the tool string, cause misalignment in the downhole string and assembled tools. The stresses imposed can interfere with smooth tool operations.

In a cased hole, cement bond keeps the casing string in place and prevents its movement during regular well operations. In open holes the production string is free to move sideways. The movement can be caused by fluid flow inside the off-center string. If these movements occur in the more flexible part of the tubing string, they can interfere with the opening of the sliding sleeves.

While any one of these considerations by itself may not be enough to prevent tool operations, they collectively have the potential to do so.

Recommendations

The wellbore area adjacent to each frac port can be isolated by two packers placed at the two ends of the frac port and within a few feet of it. This arrangement can double the total number of packers used in the well (and therefore the total cost of the completion), but there are benefits from using shorter spacing between the packers. There is less thermal expansion of the tubing string between the packers. There is less chance of severe misalignment in the packed-off interval adjacent to the frac port. There is less chance of severe tubing lateral movement. And most importantly, there is a better chance of fracture containment near the frac ports.

These benefits will increase as the risk of failure is reduced. And attention to the varied issues specific to open holes will increase the probability of successful completion and production operations.