In previous posts, we explained why horizontal drilling and hydraulic fracturing is needed in unconventional shale and tight-rock formations (here) and we presented an example of the drilling and casing program for a horizontal well (here). In this post, we will address how a horizontal well is hydraulically fractured. We'll focus on the "plug-and-perf" method, which is by far the most common method. We’ll illustrate the process with a video we created but will provide some context first. If you prefer, you can skip straight to the video further down.
Overview
Hydraulic fracturing involves pumping fluid under high pressure to create a series of fractures extending out from the lateral section of the wellbore into the surrounding formation. “Proppant” (usually sand) is added to the fluid to fill the fractures and keep them open after pumping has stopped. The fractures create a multitude of easy-flow pathways for oil and/or gas to reach the wellbore, which increases both the total recoveries and the rate of recovery from the low-permeability rock.
Stages
Hydraulic fracturing is done in a series of “stages” starting at the toe of the well. The length of stages can vary by area, by formation and by operator but are commonly around 250’. Stages are necessary because it takes a tremendous amount of pumping horsepower to create fractures so it is only practical to do a limited amount at a time. Also, fracture patterns are easier to control in small stages and can be implemented more uniformly. The number of stages will depend on the length of the lateral and the length of the stages. A 10,000 foot lateral with 250’ stage length would have about 40 stages.
Perforations
When the hydraulic fracturing process begins, the wellbore is completely sealed off from the formation by cemented casing. Thus, the casing has to be perforated with perforating guns in each stage in order for the frac fluid to enter the formation and thereafter for production to enter the wellbore. Perforating guns do not use bullets because the bullets would lodge in the pathways they create, impeding flow. Instead, the guns fire "shaped charges" that each focus their explosive power into a high-velocity penetrating stream. The stream is powerful enough to penetrate through the casing and surrounding cement plus several inches into the formation. The perforations are made in a pattern of spaced “clusters.” The designs vary widely but an example would be 3-6 perforations per cluster with clusters 20’-30’ apart throughout each stage.
Frac Plugs
After each stage, a frac plug is set in the casing a short distance uphole to isolate that stage from the next stage to be fractured. The plug blocks flow during fracturing of the next stage so that the fluid is forced through the new perforations rather than flowing past the plug where it could escape through prior fractures.
A setting tool is used to set the plug, and the setting tool with plug below are connected to the bottom of the perforating gun string. This “bottom hole assembly” is then lowered down the well on electrical wireline and then pumped down the lateral section to the plug set point. An electrical signal is then sent down the wireline to activate the setting tool (most setting tools are powered by an explosive charge inside the tool). The setting tool forces gripping and sealing devices on the plug to expand tightly against the walls of the casing. Once set, the setting tool and plug separate and the perforating guns are raised and fired at the various perforation points. The bottom hole assembly is then raised back to the surface.
The plug has a channel through the middle that is still open at this point . The channel allows fluid to flow through the plug in both directions, but down-hole flow will be blocked off before fracturing operations begin. The most-common blocking method is to drop a ball into the well and pump it down until it reaches the plug. When hydraulic fracturing begins, the pressure will force the ball into a ball seat at the channel opening, blocking flow. After fracturing, upwell flow can still occur because flow in that direction will cause the ball to drop away from the ball seat. Some plugs have a “caged” or “in place” ball that is integrated into the plug and seats when frac pressure is applied. This eliminates the time and fluid needed to pump a ball down from the surface.
The plugs will have to be removed after all of the stages have been fractured and most plugs are made primarily of non-metallic composite material so that they can be drilled away by a coiled tubing rig using a milling bit. However, plugs made of dissolvable material are becoming more common.
Fracturing Fluid
After perforating and before fracturing, a dilute acid solution is usually pumped through the perforations to dissolve any residual casing cement that may be obstructing the flow paths. Some types of formation rock can also be partially dissolved by acid.
The fluid used for hydraulic fracturing is usually water with friction-reducing chemicals added, often called “slickwater.” A pump of a given horsepower can pump slickwater at a significantly higher rate than regular water, thus improving fracturing performance and efficiency. Other chemicals may also be added, such as corrosion inhibitors, scale inhibitors and biocide. The chemical component in frac water (before proppant/sand is added) is typically around .5% and no more than 2%. Fluid volumes used during fracturing have increased over time and the current average is around 30 barrels per lateral foot.
The type and quantity of proppant pumped with the frac fluid varies. It is important that the proppant is strong enough to resist crushing so that the fractures don’t close over time. Expensive, high-strength ceramic proppants have been tried but the industry has mostly settled on suitable-quality sand from local sources, which is much cheaper. Fine sand is pumped first with grains small enough to fit into the narrowest fractures far from the wellbore and coarser sand is pumped afterward to prop open larger fractures near the wellbore. Some wells have been fractured using as much as 4,000 pounds of proppant per lateral foot, but the current average is around 2,000 pounds per lateral foot. That’s a lot of sand, and some oil and gas companies have established their own sand-mining operations.
Video Summary
Following is a video we produced that illustrates what we have discussed so far. You can boost it to high definition if you expand to full screen and click on the wheel on the bottom right of the video and select "quality."
For those who are curious, why were the first perforations made by the well-service rig and the rest by the frac crew? It’s because the first perforating guns have to be pushed to the end of the well and a tubing string was used for that purpose (a “coiled tubing” rig is typically used because it is quicker than a rig that uses tubing joints as you saw in the video). After the frac crew arrives and fractures through those first perforations, fluid can thereafter be pumped down the well and out the fractures. This allows the bottom hole assembly for each subsequent stage to be pumped (rather than pushed) into position.
Fractures
The longest fractures generally extend at least 200’ horizontally from the wellbore and sometimes much further, depending on operator well spacing and program design. A general objective is to fracture as far as possible without intersecting fractures from surrounding wells. The target formation is commonly less than 300’ thick so vertically-oriented fractures usually do not extend as far. An easily-fractured formation like shale may be sandwiched between harder rock layers such as sandstone or limestone and vertically-oriented fractures generally stop at those harder layers.
Shale is brittle and layers will contain varying degrees of natural fractures prior to hydraulic fracturing. Operators often orient wellbores in a direction that ensures that new fractures are created rather than having frac fluid take the path of least resistance through existing natural fractures.
When fractures are created, they make a popping sound in the subsurface. Sometimes operators use a seismic method called “micro seismic” that can detect and identify the source location of those sounds. That information can be used to roughly monitor fracture patterns in real time during fracturing. Adjustments can be made in pumping pressure, pumping duration and other variables in an attempt to optimize results.
Zipper Fracs and Simul-fracs
Originally, one wellbore would be fractured at a time. “Zipper Fracs” are more common now, whereby two wells on a multi-well pad undergo operations at the same time. A manifold is installed so that frac fluid can be diverted to either well, and the process goes back and forth like teeth on a zipper so that one well is being prepared for the next stage while the other is being fractured.
A process called “simul-fracs” is emerging such that four wells undergo operations at the same time. Two are fractured simultaneously (requires more pumping power than zipper fracs) while the other two are being prepared for the next stage simultaneously.
The industry is also making advances toward “intelligent fracturing” that would incorporate automated monitoring and control to improve results during the fracturing process.
Design Variables
Hydraulic fracturing is far from an exact science and can have a high degree of variability in fracturing quality from cluster to cluster, stage to stage, and well to well. The industry is constantly working on new tools and techniques to improve results, save time and lower costs. They are also working on environmental issues such as reducing fracturing fleet emissions and conserving water usage.
Key variables in fracturing process design include pumping pressure, fluid type and volume, proppant type and quantity, stage spacing, cluster spacing, wellbore length and orientation, frac plug design, etc. These variables affect not only results, but also costs. The ultimate goal of unconventional development is to generate an optimal return on investment, and experimentation has shown that more-rigorous programs do not always achieve better results.
Hydraulic fracturing is expensive and is the largest single cost for a horizontal well. As a rough example, a horizontal well with a 10,000 foot lateral section might cost around $8 million. Of that, drilling costs would be about $2 million, hydraulic fracturing would be about $4 million, and the remaining $2 million would be other completion costs to equip the well for production and to install flowlines and surface facilities.
Sliding Sleeve
A lesser-used fracturing method that we did not cover is called "sliding sleeve" or "ball-activated sleeve." It involves installing a long assemply with sliding "sleeve" components in an open-hole lateral section (no production casing). Progressively-larger balls are pumped down the well after the fracturing of each sleeve section to slide the next sleeve forward so that it closes off the prior section and opens up and isolates the next section to be fractured.
Coming Next
In our next post, we address what happens after fracturing is complete, including milling plugs, flowback, tubing and packer, wellhead, flowlines and surface equipment.
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