Hydraulic fracturing is by far the most common technique used to break up the rock, and several strategies to create a hydraulic fracture network along the lateral have been developed throughout the years.
by Neil Stegent (Pinnacle – a Halliburton Service)
April 15, 2016

The primary difference between conventional and unconventional reservoirs is the matrix permeability of the reservoir rock. Permeability is the rate of flow of a gas or liquid through a porous medium. Conventional reservoir completions rely on good permeability, where the hydrocarbons flow freely out of the reservoir rock. To be economically viable, unconventional reservoir completions must overcome ultra-low permeability by having increased surface area exposure in the reservoir source rock. Typically, unconventional reservoirs have permeabilities in measured units of nanodarcies (nd), while conventional reservoir permeabilities range from millidarcies (md) to Darcies (D). As a reference point, a single brick used in a home typically has permeability in the md range. Conventional onshore reservoirs are typically drilled and completed with vertical wellbores. The drilled hole has steel casing cemented in place, and this conduit is used for production and to complete the reservoir horizons of interest. Several forms of stimulation systems are used, with hydraulic fracturing and fracture acidizing the two most prominent techniques. Source-rock-reservoirs (typically called shale) can be economic producers of hydrocarbon if the wellbore is drilled horizontally through the hydrocarbon-bearing rock and hydraulic fractures are created along the lateral. The Barnett Shale is probably the most widely known shale, both within and outside the industry. Hydraulic fracturing is by far the most common technique used to break up the rock, and several strategies to create a hydraulic fracture network along the lateral have been developed throughout the years. Two of the most common completion strategies to create fractures are plug-and-perf (P-n-P) and ports-and-packers. Other completion strategies—such as slotted liners, coiled tubing (CT) and fracturing—are used as well, but these two strategies are the most common.

Cemented casing for P-n-P completionFigure 1. Cemented casing for P-n-P completion (Images and graphics courtesy of Pinnacle – a Halliburton Service)


The P-n-P strategy is the most commonly used completion technique in North America. It can be implemented in both cemented and openhole completions. Figure 1 shows an example of a cemented horizontal, but the cemented annulus can be replaced with an external packer system. This completion strategy is extremely flexible, efficient and low-risk. Real-time treatment design changes can easily be implemented if necessary. When a P-n-P completion strategy is employed, the first planned fracture stage nearest the toe of the horizontal is perforated. This can be achieved by perforating with tubing-conveyed perforating (TCP) on CT. Another option is to place a hydraulic valve in the casing string and then open it by pressuring up on the production casing to a predetermined value. Either method can enable an open system, allowing fluid to be pumped through the casing and into the formation.

Fracture plug and setting toolFigure 2. Fracture plug and setting tool

This process is only performed during the initial fracture stage. Once the first stage has been perforated and the hydraulic fracture treatment has been completed, wireline is deployed into the well. The wireline is equipped with a fracture plug and perforating guns to allow completion of the next fracture stage (see Figure 2 and Image 1). A fracture plug acts as an isolation device between fracturing treatments, similar to a bridge plug. But it allows the well to flow in the opposite direction, acting as a check valve. A ball is used to seal against the fracture plug, allowing the treatments to be isolated, and is then unseated when the well is produced (see Image 2).

Fracture plug and isolation ballImage 2. Fracture plug and isolation ball

Once the wireline has reached a point in the heel of the casing string where gravity will no longer have an effect, the plug and guns are pumped down the lateral to the necessary position. The fracture plug is hydraulically set in the lateral, and the perforating guns detach during this operation. The perforating guns are then pulled by the wireline to the desired location, which is planned for the lowermost perforation cluster. Select fire of the perforation guns then perforates the casing/cement/formation.

Perforating guns after being fired and taken apart.Image 3. Perforating guns after being fired and taken apart.

The perforation guns are moved to the remaining planned perforation cluster positions in the lateral, and the perforating process is repeated. Once all the clusters for that fracture stage have been perforated, the guns are pulled out of the well, and the hydraulic fracture treatment can be completed (see Image 3). The process of setting the plug, perforating and fracturing is repeated along the entire length of the lateral, ending in the heel of the horizontal wellbore. Hence, the name of the completion strategy is P-n-P. The P-n-P process is extremely flexible, efficient and low-risk. The flexibility allows the completion engineer to alter the number of perforation clusters, the distance between perforation clusters and the length of each cluster during completion. Sections of a lateral can even be bypassed if the quality of the reservoir is poor and uneconomic, which could happen if an unknown fault was intersected during drilling. Hydraulic fracture treatment designs can easily be altered during the treatment, if necessary.

Ports-and-packers completion in open holeFigure 3. Ports-and-packers completion in open hole


The ports-and-packers strategy is another commonly used completion technique in North America and is primarily implemented in openhole completions. Figure 3 shows an example of a ports-and-packers completion strategy in a horizontal well. Fracture ports are installed as part of the casing string and placed in the open hole with external packers in the annular section. This configuration can also be cemented in place without the external packers, but it is highly recommended that only acid soluble cement be used.1 The external packers can be activated by hydrocarbon swelling or by a mechanical set. The external packers are used instead of cement to provide isolation between the fracture stages on the outside of the casing in the annular space. This completion strategy is not as flexible as the P-n-P system because the position of the ports is determined as a part of the production casing. However, ports-and-packers systems are very efficient. In theory, the entire wellbore could be hydraulically stimulated without ever stopping the fracturing pumps. This system’s risk is in the low-to-moderate range. A great deal of pre-job planning is required during the drilling phase to help ensure the sequence of the baffles are correctly installed. Real-time treatment design changes in the location of the fracture ports cannot be implemented because they are part of the production casing. The fracture ports provide the same function as the perforation clusters in the P-n-P process. In a ports-and-packers completion strategy, the end of the steel casing is an open-drilled hole and free of any cement blocking. The first fracture stage can be pumped directly out of the end of the casing into the formation. A hydraulic opening valve is typically placed in the casing string to help ensure that an open system can be achieved to successfully pump the initial hydraulic fracturing stage. TCP cannot be used as part of this completion strategy because the inside diameter (ID) of the fracture port baffles is too small for the TCP guns to pass through.

Fracture port balls and diameter gaugeImage 4. Fracture port balls and diameter gauge

Once the initial fracture stage has been completed, a ball of specific gauge diameter is dropped into the flow path and pumped into the well (see Image 4). Each fracture port is fitted with a specific diameter baffle and has a corresponding isolating ball, which is used to isolate sequential hydraulic fracturing treatments inside the casing from the previous treatment (see Figure 4).

A fracture port schematic with a ball and baffleFigure 4. A fracture port schematic with a ball and baffle

The fracture port baffles have different IDs, with the smallest ID at the toe of the horizontal and the largest at the heel. This allows the smaller ball to pass through the fracture ports at the heel and travel the length of the lateral to the fracture port at the toe. The ball lands on the fracture port baffle, and pressure increases to a predetermined value. Once the pressure reaches that value, the shearing pins inside the fracture port open it. This opens ports in the casing string, allowing fluid to pass from inside the pipe to the annular space between the external packers. Increased pressure and pump rate causes tensile failure of the reservoir rock, and a hydraulic fracture is initiated. When the hydraulic fracture treatment is completed, another properly sized ball is dropped into the well to initialize the next treatment stage. This process is repeated until all the ports have been opened and fracture treatments have been pumped. References

  1. Stegent, N.A., Leotaud, L.M., Prospere, W. et al. 2010. Cement Technology Improves Fracture Initiation and Leads to Successful Treatments in the Eagle Ford Shale. Presented at the SPE Tight Gas Completions Conference, San Antonio, Texas, 2–3 November. SPE-137441-MS. http://dx.doi.org/10.2118/137441-MS.