Fracturing Zones

Determination of Fracture Zone Spacing

The vast majority of modern gas producing wells are drilled horizontally. The drill bit enters the surface vertically, but as the borehole approaches the target formation, the drill is steered until it is horizontal. After entering the horizontally bedded producing formation, the borehole can extend horizontally for thousands of feet.

The earliest fracture jobs in the 1940s were focused on reducing skin damage near the borehole in vertical wells, and could be completed in one stage. In contrast, a horizontal shale gas well is often fractured in 20-60 stages or more. In each stage, a section of the wellbore (generally 100-500 feet) is isolated and fractured.

Why complete hydraulic fracturing in stages? There are several reasons:

• Lower pumping rates and pressures: By isolating relatively short segments of the wellbore, the pressures and pumping rates needed to create the desired fractures is decreased. It would be very difficult to fracture an entire horizontal well by pumping – the pumping capacity required would be astronomical.
• Customization for different rock characteristics: If the well passes through a heterogeneous source rock, each stage can be customized to maximize effectiveness for the local unit conditions.
• Separate analysis of individual well segments: By fracturing in stages, operators can collect higher resolution data about the results of fracturing at different places along the wellbore.

All modern horizontal gas wells are fractured in stages. However, the spacing and length of each stage can vary significantly.

The primary determinant of fracture stage spacing is economic: what fracture stage spacing will result in the greatest profit?

It all comes down to the interplay between the amount of pumping required to fracture a certain area and the cost of setting up each additional stage. When the fracture stages are closely spaced, less pumping capacity is required to fracture each one but doing this will add more time to the process, because of the increased number of stages. When they are far apart, more pumping capacity is needed but less time is required to complete the total length of the production zone.

Fracturing Zone Isolation Systems

Hydraulic fracturing also requires some underground setup. The crew needs a way to isolate the zones from each other downhole. Because of the high pressures involved, they really need to make sure that there’s a tight seal separating the zone actively being hydraulically fractured from the rest of the well.

The method chosen for isolating the zones depends partly on whether the well has an open hole completion or cased completion.

There are two common systems for isolating well stages: plug and perf (short for plugging and perforating) and sliding sleeve.

Each system requires an entirely different approach and has a unique set of advantages and disadvantages.

Plug and Perf

The plug and perf method is designed for cased completions.

It involves alternating between two modes: stage isolation and pumping. Isolation and fracturing begins at the toe of the well (the end furthest away from the wellhead) and proceeds in stages towards the heel (the curve taking the well from vertical to horizontal).

• Stage Isolation: This is the “plug” part of the plug and perf method. In this phase, a wireline truck is used to lower a plug to the lowermost end of the zone (for the first zone, no plug is needed). The plug can be set using a variety of mechanisms, including electrical actuators and chemical means. The purpose of the plug is to seal one section of the wellbore off so that pumping pressure can be focused on the part of the well immediately before that section.
• Perforation: After a plug has been placed at the lower end of the zone, a wireline tool is used to perforate the well casing at the desired fracture locations. The perforations will allow fracturing fluids to enter the formation and will eventually be the conduits through which gas enters the well.
• Pumping: After the borehole has been plugged and the casing perforated, wireline tools are removed from the well entirely, pump trucks are brought online, and pumping of fracture fluids begins. Since the borehole is lined with casing, the fluids will only enter the formation through the perforations adjacent to the plug. After fracturing of the zone is complete, operators start the process again by installing a new plug further up the pipe.

After all the stages are complete, in many cases a drill bit is used to drill out the plugs, reconnecting all of the zones and allowing gas to flow out.

The main advantage of the plug and perf method is its simplicity – there isn’t much that can go wrong downhole. Since wireline tools enter the well for each zone, any problems encountered can usually be corrected.

The primary disadvantage of plug and perf is that the operators must repeatedly switch between wireline operations and pumping operations. This constant switching adds time and logistical complexity to fracturing operations.

The Sliding Sleeve Method

The sliding sleeve method is ideal for open-hole completions.

The sliding sleeve method involves a movable production liner with built in expanding plugs and ports that are activated by dropping metal or composite balls into the liner. Each ball is perfectly sized to plug up one section of pipe when it gets to the intended section.

The ports perform the role of perforations in a cased well, and the plugs serve to isolate zones. The mechanical system at the toe of the well requires the smallest ball, and the ball size required increases towards the heel of the well. By inserting balls in the correct order (small to large) each zone can be isolated and activated in turn.

Let’s take a look at the process one step at a time:

1. Liner configuration: First, operators plan out the zones and decide how they will assemble the production liner. Typically, the sliding sleeve system consists of segments containing plugs and sleeves interspersed with simple metal casing tubes that can be added and removed to adjust the size of each zone. As the liner is lowered into the well, new sections are added according to the plan.
2. Liner placement: The entire production liner is lowered into the well until it has reached the desired depth.
3. Zone isolation: The ball associated with the lowermost zone is pumped into the well. When the ball is set in the actuator matched to its size, two things happen. First, the plugs at the bottom and top of the zone are activated, isolating the zone. Second, a sliding sleeve is activated, opening holes in the production casing just up the hole from the last plug.
4. Pumping: Pump trucks are engaged and the zone is fractured. After fracturing, operators drop another ball, which closes off the zone just fractured and isolates the next zone.

The process is repeated with progressively larger balls until all the zones have been fractured.

At the end of the process, the pressure is reduced, allowing natural formation pressure to reverse the direction of flow. This pushes all the balls to the surface and initiates oil and gas flow through the production casing. Alternatively, the entire interior of the casing can be reamed out, increasing the cross sectional area available for flow.

This system is clearly more complicated than the plug and perf method, and there are more things that can go wrong. A ball might not form a good seal in the valve seat due to the presence of sediments. In addition, the mechanical components in the sliding sleeve liner are complex and may fail. Either of these scenarios could result in the inability to fracture one or more zones of the well. And woe betide the one who drops the balls in the wrong order (unlikely, but the consequences would be expensive)! It’s worth the risk though, because once the liner and sliding sleeve are in place, and if everything works correctly, the sliding sleeve system can dramatically speed up the completions process.

Fracturing a Zone

After each zone is isolated, hydraulic fracturing operations begin. Effective fracturing requires a complex orchestration of many different processes including fracture fluid mixing, pump control, and fracture monitoring.

Several types of fluids are pumped sequentially into the borehole during the hydraulic fracturing job.

The first fluid to enter the borehole during pumping is typically a hydrochloric or citric acid solution tailored to the chemistry and mineralogy of the productive units. Its purpose is to clean out the borehole and remove any scaling that may have built up during drilling and perforating. This stage might contain several thousand gallons of fluid.

After the acid comes a fluid stage referred to as the pad. The purpose of the pad is to initiate fractures and prepare them to accept proppants. The pad is typically a slickwater solution, one that serves to decrease the friction acting on the flowing fluids and allow them to flow more easily. Sometimes the pad includes gelling agents to increase viscosity. A pad volume of around 100,000 gallons is typically used.

After the pad, proppants start to be added to the slickwater solution. Typically, proppant concentrations will be increased in steps as the fractures grow. This maximizes the total amount of proppant that can be delivered.

Once the fractures reach the desired size or stop growing due to leak-off, the well is shut in. As water continues to escape through the sides of the fracture, the rock closes in on the proppants, squeezing them in place. If the well was not shut in, proppants would not be set because fluids would flow back towards the surface instead of into the formation, taking the proppants with them.

Finally, water is used to flush any remaining proppants from the wellbore. At this stage, gel-breaking agents are also added if gel was used to increase viscosity during proppant delivery. These agents counteract the effects of the gelling agent once its job is done, lowering the viscosity to control formation damage and allow for better oil and gas flow.

Monitoring a Fracturing Job

The best way to tell what’s going on underground during hydraulic fracturing is to monitor the pump pressure. If conditions underground were constant, the pressure would depend only on the pumping rate of the trucks. However, as we know, there are many factors that can cause changes in pressure for a given pumping rate.

A typical plot of pressure through time during a hydraulic fracturing operation looks something like this:

As pumping begins, pressure rises within the fracture zone and borehole tubing (up to the point labeled Breakdown pressure). Once it exceeds the sum of the least confining pressure and the tensile strength of the rock, the rock fractures. As the fractures grow, their surface areas increase, resulting in increasing rates of fluid leak-off and declining pressure (Fracture extension pressure).

When the fracture has grown to the desired length or stopped growing due to leak-off, the well is shut in, which causes an instantaneous drop in pressure (Initial shut-in pressure). As the fracture closes around the proppants, the excess pressure bleeds off and pore pressure near the fracture returns to normal (lowest point at the end of the curve).

If pumping resumes, the fracture fluids will bleed off through the fracture as the pumping rate increases. Sometimes, operators will resume pumping in a fractured zone to learn something about the characteristics of the rocks that were fractured. This is known as a leakoff test.

Images: “Frack Ball” by Jim Blecha; “Diagram” by Top Energy Training