Section 2 _Types of Frac

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Hydraulic FracturingSection 2 Types of Hydraulic Fracturing

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2. Types of Hydraulic Fracturing

There are various different types of hydraulic fracturing, which have evolved around the basicprocess of creating a fracture and then propping it open. The type of treatment selected

depends upon the formation characteristics (permeability, skin damage, fluid sensitivity,formation strength), the objectives of the treatment (stimulation, sand control, skin bypass or acombination) and the constraints we have to work within (cost, logistics, equipment etc).

2.1 Low Permeabil i ty Fracturin g

This type of fracturing is often carried out in tight gas formations, found in areas such as theRocky Mountains, Algeria, Western Germany, parts of Australia and many other places world-

wide. Permeabilities for such formations range 1 md right down to 1 d and less. This type oftreatment is also applicable to low permeability oil formations, although permeabilities tend to1 or 2 orders of magnitude greater.

In order for hydrocarbons to flow down the fracture, rather than through the adjacentformation, the fracture must be more conductive than the formation. Given that the kp for20/40 Colorado Silica frac sand is 275 darcies (provided closure pressure is below 3,000 psi),we can see that even a very narrow fracture will have a much higher conductivity than theformation itself. This does not allow for non-Darcy flow (see Section 7).

Therefore, the limiting factor defining how much the reservoir production has increased is nothow conductive the fracture is, but instead is how fast the formation can get the hydrocarbonto the fracture. Therefore, when treating low permeability reservoirs, fractures should bedesigned with a specified minimum fracture conductivity, but a large surface area.

Because formation permeability is low, fluid leakoff also tends to be low. This has twoconsequences. First, pad volumes tend to be very low, relative to the rest of the job volumes.

In some cases, a pad is hardly needed at all the proppant-laden fluid can be used to createthe fracture. The second consequence is that fracture closure time the length of time takenfor the fracture to close on the proppant after the treatment has finished tends to be long.This means that the fracturing fluid has to suspend the proppant for a relatively long period oftime at bottom hole temperature.

Therefore, hydraulic fracture treatments in low permeability formations tend to have fairlylarge fluid and proppant volumes, although the overall proppant concentration in the fluid isrelatively low. Pad volumes are small. Treatment fluids are usually fairly robust, capable ofmaintaining viscosity for longer periods of time.

2.2 High Permeabil i ty Fracturin g

High permeability fracturing is, not unexpectedly, the opposite of low permeability fracturing.In high permeability formations moving the fluid through the rock to the fracture is easy. Thehardest part is creating a fracture that is more conductive than the formation in the nearwellbore region.

In equation 1.8, the concept of fracture conductivity was introduced. The next step is to definerelative or dimensionless conductivity, Fcd:-

Fcd =Fc

L kf................................................................................. (2.1)

where L is the fracture half length and kf is the permeability of the formation. Fcd is a measureof how conductive a fracture is compared to the formation. An Fcd of greater than one means


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that the fracture is more conductive than the formation, whereas an Fcd of less than onemeans that the fracture is less conductive than the formation and the reservoir fluids flowmore easily through the formation. This does not account for the effects of the skin factor inreality all the fracture needs to be in order to increase production, is more conductive than theskin (see Section 2.4 Skin Bypass Fracturing).

From equation 1.8, which stated that Fc = W .kp , we can see that two parts of the definition ofFcd are fixed; kf and kp (although kp can be increased to a certain extent by using a betterquality proppant). Therefore, in order to increase dimensionless conductivity, we have tomaximise W and minimise L. This means that we need a very short, wide fracture. In order toachieve this, a technique known as the Tip Screen Out (TSO) is used. This will be discussedin more detail later on.

Because the formations have high permeability, fluid leakoff tends to be very high. Therefore,pad volumes tend to be a significant part of the treatment. This high leakoff is used by thetechnique of TSO fracturing. Youngs modulus tends to be very low, which means thatcreating fracture width is relatively easy.

Formations with very high permeability also tend to have two other characteristics. First, they

are often weak or unconsolidated, so that the fracturing process is often combined with gravelpacking techniques to produce a frac pack treatment (see below, Section 2.3). Second, theformations also tend to have large skin factors, so that a significant production increase canbe obtained simply by providing a conductive path through the skin (see Section 2.4, below).

2.3 Frac and Pack Treatments

The frac and pack (or simply frac-pack) treatment is a combination of a high permeabilityfracture treatment and a gravel pack treatment. Technically, the process of designing theactual treatment is the same as for a high permeability frac. Operationally, however, theprocess is much more complex, due the presence in the hole of the gravel pack completion.Figure 2.3a illustrates this.

Figure 2.3a Diagram Illustrating the Components of the Frac-Pack Completion

GPS-2 Tool

Crossover Ports

Blank Pipe

Screens

Sump Packer


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The treatment is normally pumped with the GPS-2 tool in the squeeze position, althoughsometimes the tool is in the lower circulating position. In either case, fracturing fluids arepumped down the tubing, through the GPS-2 tools, through the crossover, out into theannulus and into the perforations.

As stated before, the pumping schedule a designed as if the completion did not exist, and a

normal high permeability fracture treatment was being performed. With one exception extraproppant (or gravel) is pumped on the final stage, in order to fill up the annulus spacebetween the screen and the casing, producing the gravel pack

2.4 Skin Bypass Treatments

Skin bypass treatments are designed to do exactly what the name describes bypass skindamage. These treatments are not necessarily designed to be the absolute optimumstimulation treatment for the well. Instead, these treatments are designed to be small, costeffective and easy to run operationally. Often these treatments are pumped in places wherespace or equipment weight is a limiting factor such as offshore. In many cases, if the fracengineer was given a free reign to design the optimum treatment, the job itself would be muchlarger. However, given the restraints of cost and space that are often placed upon fracengineers, the skin bypass frac is an attempt (often highly successful) to produce effectivestimulation.

The skin bypass frac can also be considered as an alternative to matrix acidizing, whenfactors such as mineralogy, temperature, logistics and cost prevent the use of acid.

Figure 2.4a Diagram Illustrating hoe the Skin Bypass Fracture Penetrates the Skin to allowUndamaged Communication between the Reservoir and the Wellbore.

Figure 2.4a shows the basic concept behind the skin bypass frac. Although the formation hasconsiderable damage (dark-shaded area), this is effectively bypassed by the more conductivepath created by the fracture. In order for the fracture to produce a production increase, it doesnot have to be more conductive than the formation (i.e. Fcd > 1.0). It merely has to be more

conductive than the damaged area. Of course, usually we are aiming for considerably morethan just an increase in production. Given that Skin Bypass Fracs are normally carried out on


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marginal wells (wells that cannot justify the expense of a major stimulation treatment), oftenthe economics dictates that significant production increase must be obtained. Equation 2.1gave the definition of dimensionless conductivity, which has to be greater than 1.0 for thefracture to provide stimulation of the formation. Equation 2.2 shows the condition, for a

fracture which has HD 1.0, under which the skin bypass fracture is more conductive than theformation:-

Fc

H kf >

ln (re/rw)

ln(re/rw+ S)................................................................. (2.2)

where Fc is the fracture conductivity (mdft), His the fracture height (ft), re is the radial extent(ft), rw is the wellbore radius and S is the skin factor. So ifS = 0, the RHS of equation 2.2 goesto 1, so that then Fc has to be greater than H.kf , which is another way of saying that the Fcdhas to be greater than one. This equation takes into account the fact that the fracture doesnot cover the entire zone vertically. However, it is an approximation, as it does not account forvertical flow or non-Darcy effects (Section 7).

2.5 Coal Bed Methane Fracturin g

It is estimated that for every tonne of coal that is generated underground - by the process ofcoalification - up to 45 mscf of gas (mostly methane) is generated. In areas such as theSouthern North Sea, this gas migrates upwards until it reaches an impermeable layer, so thatthe coal itself contains very little gas. In other cases, nearly all the gas remains in place,waiting to be produced.

Coal itself usually has very low matrix permeability, with the gas being produced throughnatural fractures (called cleats) and through desorbtion from the coal itself. The objective ofcoal bed methane fracturing is to connect up the cleats with a propped fracture, allowing thegas to be produced both from the cleats and from the coal

CBM fracturing is more of an art than a science. Because of the unusual characteristics of theformations, most fracture simulators are unable to accurately model these treatments.Engineers usually have to rely on experience and trial and error.

These treatments usually consist of large volumes of proppant, pumped at lowconcentrations, at high rates. Various fluid systems have been used, but recent work hasdemonstrated that crosslinked fluids, especially guar-based gels, can be very damaging to theformation. The trend has been towards HEC, foams and even just water as the carrier fluid.Recent advances like visco-elastic surfactants and Liquid Proppant could also find aapplication in this area, although cost would be a big issue with visco-elastic surfactants.

Proppant concentrations tend to be in the 3 to 4 ppg range. Because wells are relatively lowrate, large fracture conductivities are not required what is needed is a conductive path from

cleat to cleat. As formations are usually shallow, sand is generally selected as the proppant.

CBM wells often tend to be marginal. They will not produce economically without a fractreatment, but even after a frac can be very low rate. Therefore, fracturing treatments tend tobe fairly low tech, no frills operations, using minimal fluids technology and often eliminatingthe need for modern, sophisticated, computerised blending and pumping equipment.

2.6 Fractur ing Through Coi led Tubing

Fracturing through coiled tubing has been around since the early 1990s, and was first carriedout through a string of coiled tubing that was left in the well after the treatment, becoming theproduction tubing. However, as the industry began to perceive the advantages of this process and as Engineers began to leave their preconceived coiled tubing ideas behind theconcept has become widely accepted.


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The advantage of coiled tubing fracturing does not lie with the design or type of fracture that isplaced in the ground, as most types of fracture can be performed this way. The benefits of CTfracturing lie in the operational aspects of how the treatments are placed.

The obvious limitation for coiled tubing fracturing is the diameter of the coil and the maximum

pressure it can be taken to. However, this restriction is not nearly as bad as it initially seems.With modern fluid systems, friction pressure down the coiled tubing can be dramaticallyreduced, allowing treatments to be pumped at quite high rates. Also, as the coiled tubing isstatic during the treatment (i.e. the tubing is not being plastically deformed on a continuousbasis), the maximum allowable pressure is far higher than is normal for CT operations.

Advantages

1. The coiled tubing can be used to isolate the completion from the fracturing process.By setting a squeeze packer at the end of the tubing, the hole tubing string isprotected from the pressure and temperature changes normally experienced by thecompletion. This means that completions that are pressure-limited (due to slidingsleeves, packer ratings, poor quality tubing, wellhead size etc) can be fractured.Completions which cannot be cooled down too much (due to risk of stinging thetubing out if the PBR on the packer), can also be fractured.

2. Coiled tubing fracturing is particularly effective when working on monoborecompletions, or on wells that have not yet been completed. By using an opposing cuptool, the coiled tubing can be used to easily isolate one zone from another. Anextension of this, is that the tool can be very easily moved from one zone to another,allowing multiple fracs to be performed in rapid succession.

3. If required, the coiled tubing can be used to gas lift the well on to production after thetreatment(s).

4. Coiled tubing can often be used as an alternative to a workover. This can meansignificant cost saving, especially offshore.

Disadvantages1. The extra cost of the coiled tubing unit, over and above the cost of the frac spread.

However, often this extra cost can produce savings in other areas (rig time, frac crewtime etc). The operating company must also be prepared to pay for some or all of thecost of the coiled tubing string.

2. The extra space needed, due to the extra equipment required as compared to thefrac spread by itself. Of course, if the CT unit is being used as an alternative to aworkover rig, this may not be as significant.

3. Rate limitations. In general, for a given fluid system, higher rates can be achievedthrough completions than through coiled tubing. However, it should be rememberedthat it is usually possible to take the static coiled tubing to higher pressures than thecompletion/wellhead assembly.

4. Although it is possible to frac through coiled tubing with standard fluid systems, as the

depth increases and/or the coiled tubing diameter decreases, it may be necessary touse more exotic and expensive fluid systems.

References

Product Catalogue, Colorado Silica Sand, 1994

Economides, M.J., and Nolte, K.G.: Reservoir Stimulation, Schlumberger EducationalServices, 1987.

Gidley, J.L., et al: Recent Advances in Hydraulic Fracturing, Monograph Series Vol 12, SPE,

Richardson, Texas (1989).

Bradley, H.B. (Ed): Petroleum Engineers Handbook, SPE, Richardson, Texas (1987)


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Rae, P., Martin, A.N., and Sinanan, B.: Skin Bypass Fracs: Proof that Size is Not Important,SPE 56473, presented at the SPE Annual Technical Conference and Exhibition, Houston,October 1999.

ODriscoll, K.: Middle-East Region Coal Bed Methane Fracturing Manual, BJ Services, 1995.

Gavin, W.G.: Fracturing Through Coiled Tubing Recent Developments and CaseHistories, SPE 60690, presented at the 2000 SPE/ICoTA Coiled Tubing Roundtable,Houston, April 2000.

Section 2 _Types of Frac

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