An important element in a fracture design is the
The discharge coefficient is a factor used to calculate frictional pressure drop of fluid passing through the perforations. Perfora-tions have an initial discharge coefficient of about 0.6. After you begin pumping proppant, the sand erodes the perforations and the discharge coefficient usually increases to around 0.95. The higher the discharge coefficient, the lower the pressure differen-tial through the perforations. You should keep this guideline in mind both when designing the treatment and while pumping it.
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Through-Casing Fracturing
Most operators in the Black Warrior Basin fracture wells by pumping the treatment directly down the production casing string into the formation. To fracture through-casing, the low pressure casing head is removed and a high pressure frac valve is installed in its place.
If the wellbore contains open perforations shallower than the coal to be fractured, you should not fracture through-casing unless you are certain the shallower perforated intervals have a much higher fracture pressure than will be used during the treatment. (Shallower intervals normally have a lower fracture pressure than deeper intervals.) To help prevent fracturing shallow perforated intervals, you can isolate the perforations with a tubing and packer assembly.
Through-casing fracturing offers several advantages over the through-tubing method:
❖ Allows pumping higher injection rates
❖ Provides flexibility for fracturing multiple coal seams in a well
❖ Requires less equipment downhole and at the wellhead and is thus operationally simpler
The through-casing method can be used to fracture single or multiple coal zones. Four different through-casing wellbore configurations have been used in the Black Warrior Basin:
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Single Zone•
Multiple Zones Using Limited Entry Technique•
Multiple Zones Using Plugback Techniques•
Multiple Zones Using the Ball and Baffle Technique Each of these applications are illustrated in Figure 5-2 and are explained below.Single Zone
The simplest through-casing method involves perforat-ing or slottperforat-ing a sperforat-ingle coal seam and then pumpperforat-ing the fracture treatment down the casing into the seam. The primary wellhead equipment needed for this method is a frac valve. No downhole equipment is required. Figure 5-2 (a) shows a single-zone, through-casing fracture treatment.
Multiple Zone Using Limited Entry Technique
The limited entry technique involves simultaneously fracturing several coal seams (with differing rock properties and in-situ stresses) instead of fracturing individual seams (or groups of
Figure 5-2
Wellbore Configurations for Fracturing
seams) separately. Ideally, the propagation pressures and treating rates for each zone are controlled by the number and size of perfo-rations placed across each zone. By adjusting the number and size of perforations, you may be able to control the friction pressure through the perforations, which results in some control over treat-ing pressure into each interval. The limited entry technique has generally proven ineffective in fracturing two or more coal groups (such as the Mary Lee and Pratt or Mary Lee and Black Creek seams). However, the limited entry technique for fracturing seams within the same coal group (such as the Black Creek) is commonly used. Figure 5-2 (b) shows a limited entry fracture treatment.
Recent studies at the Rock Creek project have shown that you can successfully stimulate all seams within the same coal group through a single set of perforations in one seam of the group. This technique, called re-stricted access, was used successfully in the Black Creek coal group at Rock Creek. For more information on the restricted access completion method, refer to Accessing the
Formation in Chapter 4.
Multiple Zones Using Plugback Techniques
The most common method used to fracture multiple zones in a well is to perforate and stimulate the lowermost zone first and then successively plug back, perforate and stimulate the shallower zones. Because plugging back allows you to isolate and treat each zone individually, you can control the treatments more effectively than with the limited entry technique.
Several methods are used to plug back zones. Most operators in the Black Warrior Basin use sand plugs and/or retrievable bridge plugs to isolate zones for fracturing. Figure 5-2 (c) shows how the middle, or Mary Lee, coal group was isolated from the lower, or Black Creek, coal group using a sand plug, and the upper, or Pratt, coal group was isolated using a retrievable bridge plug.
The decision to use a sand plug or a retrievable bridge plug will depend primarily on the distance between the prospective coal zones. A sand plug may be less expensive than a bridge plug.
However, if the coal zones are separated by several hundred or more feet, using a retrievable bridge plug may be more practical than placing a large volume of sand and then washing it out of the
Multiple Zones Using the Ball and Baffle Technique The ball and baffle technique is used to isolate coal seams by installing cast-aluminum baffle plates at pre-selected depths in the casing string when the string is run in the hole. Figure 5-2 (d) shows a baffle frac job performed on Well P3 at the Rock Creek project.
To isolate a perforated interval for fracturing, a rubber ball is dropped down the casing. The ball seats in the baffle and thus isolates the interval from treated deeper intervals. By installing baffles with successively larger inside diameters (from the bottom upward), you can effectively isolate single seams or groups of seams so they can be treated individually during the fracture job.
The ball and baffle technique offers two significant advantages.
First, it saves time because you can fracture the zones in succession without having to trip tools in and out of the hole. Second, it allows you to flow back each fractured interval immediately after the fracture job. Though this technique was used successfully at the Rock Creek project, it is not widely used for coalbed fracturing stimulations in the Black Warrior Basin.
Using a Tubing "Dead String" to Measure Bottomhole Pressure To accurately determine bottomhole pressure during a fracture job, some operators run a tubing “dead string” in the well. This technique can be used with any of the four through-casing techniques described above. However, if you use bridge plugs or the ball and baffle technique, you must pull the tubing between treatments.
Figure 5-3 illustrates a tubing dead string assembly run in a well at the Rock Creek project to determine bottomhole pressure during fractur-ing of the Blue Creek seam.
Treatment fluids and proppant are pumped down the casing/tubing annulus. A pressure gauge or recorder installed on top of the tubing at the surface provides accurate surface pressure data free from frictional pressure losses. You can then convert the surface pressure reading to bottomhole treating pressure by using the equation below:
BHTP = Pt + Ph
where:
BHTP = Bottomhole treating pressure Pt = Tubing pressure at surface gauge, psi Ph = Hydrostatic pressure in tubing, psi
Figure 5-3
Tubing "Dead String” for Measuring Bottomhole Pres-sure
When using a tubing dead string, you should place the tubing as close to the coal interval as practical. You must also select a pressure gauge or recorder that has a pressure rating greater than the maximum anticipated injection pressure.
To protect the tubing from the abrasion of the sand-laden fluid, a tubing dead string assembly requires several pieces of equipment. This equipment is described below:
Blast Joint A blast joint should be installed in the tubing string through the injection spool to prevent the abrasion of the proppant-laden fluid from cutting a hole in the tubing. At the Rock Creek project, a 2-3/8 inch tubing string was used for the dead string. To eliminate the cost for a 2-3/8 inch blast joint, a 2-7/8 inch pup joint was placed over the 2-3/8 inch non-upset tubing. The pup joint was supported on the bottom by a collar on the 2-3/8 inch string and on the top by the BOP rams, as shown in Figure 5-3.
Casing Spool A wellhead fixture similar to a casing spool with side outlets allows injection of fracture fluids into the tubing/casing annu-lus. The treatment is pumped through the side ports in the spool. The spool is installed on the casing or casing head. (You may need a threaded companion flange if the casing is fitted with a threaded nipple and the spool is flanged.)
Blowout Preventer (BOP) A pipe ram BOP is installed on top of the casing spool to contain the pressure in the tubing/casing annulus during the fracture job. To provide another pressure seal for additional safety, you may also install a stripper rubber head directly on top of the BOP.
Mechanical Tubing Slips Tubing slips are placed above the BOP to support the weight of the tubing.
Coal seams may be fractured with low injection rates. However, to adequately open and widen fractures, fracturing fluids must be pumped at relatively high rates to overcome high fluid leak-off rates. Therefore, fracturing coalbed methane wells through tubing is generally impractical because sufficient injection rates cannot be established.
Through-Tubing Fracturing
Many through-casing fracture jobs are performed at rates of 25-40 BPM. The same fracturing treatment injected through-tubing would have to be pumped at a lower rate. The actual maximum injection rate will depend on the viscosity of the fluid used. You may be able to slightly increase through-tubing injection rates by adding friction reducers to the fluid.
You may justify a through-tubing stimulation in cases where through casing treatments are not possible. For example, if the wellbore contains open perforations above the coal seam to be fractured. Similarly, through-tubing fracturing may be used if pre-fracture testing indicates that fracturing pressure will exceed the differential burst pressure of the casing at shallow depths.
If you attempt to isolate perforations close to the seam you intend to fracture, you risk fracturing into the isolated perfora-tions. If the isolated perforations break down, proppant could flow through these perforations into the wellbore and stick the packer and pipe.
Selecting proper fracturing fluids is critical to a successful fracturing treatment. These fluids help initiate the fracture in the formation, extend the fracture once it opens, and transport the proppant into the fracture.
To select the best fracturing fluid for a well, you should consider these factors: