Fracturing Fluids

▲

▲▲

▲

▲ Caution

Fluid Viscosity

Viscosity may be the most critical factor in selecting a fluid. An effective fluid must not only initiate and extend a fracture, but also carry the proppant deep into the fracture. High viscosity fluids are necessary to develop fracture width and to effectively transport the proppant. A fluid with insufficient viscosity will limit the fracture width and prevent the transport of proppants deep into the fracture.

It is also important to select the appropriate breaker and breaker concentration. No matter how good the proppant transport charac-teristics of the frac fluid, they can be completely negated by using excessive breaker concentrations.

When selecting fluids, make sure you obtain viscosity information from the service company for the fluids you are considering using.

You will need this information not only when designing the fracture job, but also when monitoring the fluids during the fracture job.

To optimize the fracture treatment and prevent coal damage, the fracturing fluid must be compatible with the formation. In the Black Warrior Basin, guar gum and hydroxypropyl guar (HPG) gel fluids have been used extensively for fracturing. However, recent GRI-sponsored research has indicated that HPG gels and guar could adversely affect the permeability to both water and gas. Experience at Rock Creek has shown that guar and HPG gels can be used successfully, but they may also cause failure. For example, Wells P2 and P7 were both fractured in the Mary Lee formation with HPG gel, but Well P2’s post fracture production rate (190 MCFD) was significantly higher than that of Well P7 (40 MCFD). The poor performance of the P7 treatment was attributed to the failure of the gel to break properly, which reduced permeability.

GRI research indicates that the ability of guar-based fluids to break properly is extremely important in determining the success or failure of stimulation treatments. Conversely, research also indicates that a break schedule that is too aggressive may result in a fluid that fails to form a filter cake. A high volume of fluid could then leakoff to the cleat system and significantly impair production potential.

Field studies conducted by Amoco also indicate that HPG gel is damaging to coal. Further, Amoco laboratory studies suggest that all polymers (including HEC gels and other chemical additives) can irreversibly damage coals.

Formation Properties

The GRI and Amoco data suggest that you may reduce the possibility of damaging coal by using a fluid with low damage potential (such as KCl or a KCl substitute) or a fluid that contains a minimal amount of gel and that has a high fluid efficiency (such as foam).

Amoco has successfully fractured wells in the Oak Grove Field (Black Warrior Basin) using water as the fracturing fluid. Similarly, GRI has successfully fractured wells at the Rock Creek project using 75 quality foam as the fracturing fluid. The greater fracture lengths that can be achieved with the foam fluid may offset any formation damage that might be caused by the HEC gel used with the foam treatment.

Because nearly all coalbed methane wells are fractured through casing, frictional pressure does not usually affect fluid selection.

However, if you must fracture a well through tubing, the frictional pressure may be the limiting factor in selecting a fluid.

Because of the natural cleat system in coals, fluid losses during fracturing could be high. High fluid loss increases the probability of excessive deep damage to the cleat system.

When selecting a fracturing fluid, you must consider the cost of the treatment relative to the results expected from it. For example, if your objective is to create a short fracture that will simply ensure commu-nication between the wellbore and the natural fracture system of the coal, you may not need to use a high viscosity fluid. However, if you have determined that a very long fracture length is needed to generate economical production rates from the well, you should probably use a high viscosity fluid.

In the Black Warrior Basin, operators use only water-based fractur-ing fluids. There are four types of water-based fluids:

•

You can pump fresh water, or treated water at high rates to place low concentrations of sand (e.g., less than 1 lb/gal) into fractures.

However, if you use a water-based fluid, you will likely place the proppant a relatively short distance from the wellbore. The propped fractures from a water-based stimulation will be short because of the poor transport capacity of water and because the created fractures are close to wellbore.

▲

▲▲

▲▲ Caution

Make sure that any water used is compatible with the fractur-ing fluids you plan to pump. Do not use water flowed back from a previous fracture treatment unless it has been properly treated.

Recent research sponsored by GRI has shown that using 2% KCl (potassium chloride) water may help prevent formation damage.

You may also consider adding a natural or synthetic friction re-ducer to the water, allowing you to pump at a higher rate to carry the proppant further out from the wellbore. Friction reducers may also allow you to use lower horsepower pumps. Before using a friction reducer, make sure it is compatible with the fracturing fluids you plan to use.

You can pump hydroxyethylcellulose (HEC) gel fluids to place sand concentrations of 1 to 3 lb/gal a moderate distance from the wellbore. Because these gelling agents gel quickly, you can use them in continuous, semi-continuous, or batch processes.

Linear gels cannot hold proppants in perfect suspension. As the shear rate decreases in the fracture, the sand will settle. However, Sand-water fracture treatments are relatively inexpensive, but they also require recovering large volumes of water after the treatment.

you can obtain greater propped fracture length with a linear gel fluid than with a water-based system. Linear gels also help reduce friction and control fluid loss.

To facilitate recovery of the gel fluid after the treatment, the gel is designed to revert or “break” to the viscosity of water. This break-down allows the stimulation fluid to drain from the fracture into the wellbore.

Each service company uses different chemical systems to break gel fluids at various formation temperatures. Because the chemistry of these gel systems is complex, a carefully designed gel system is critical to the success of the fracture job.

Linear gels clean up with breakers and produced load water and can leave a highly conductive propped bed. The cost of a linear gel fracture is higher than for a water-based fracture treatment. How-ever, the longer propped length usually created by a linear gel should provide greater production than a water fracture treatment of the same size. Typically, the higher cost of a gel fracture is offset by higher production rates.

For several years, operators in the Black Warrior Basin com-monly used hydroxypropyl guar (HPG) fluids for fracturing.

However, recent research sponsored by GRI indicates that hydroxypropyl guar (HPG) fluids may adversely affect the permeability to both gas and water.

Crosslinked gels were developed to provide a water-based fractur-ing fluid with a higher viscosity than linear gels. This higher viscosity can create wider, better propped, and more conductive fractures than linear gels. The viscosity of these fluids is increased by adding special crosslinking systems and stabilizers.

Crosslinked gels can carry proppants in excess of 10 lbs/gal in suspension. As with linear gels, you can tailor crosslinked gels to break to a low viscosity fluid after fracture closure. However, crosslinked gels are more difficult to break than linear gels. To ensure recovery of the fracturing fluid and to reduce the potential for formation damage after the treatment, you should add sufficient breaker to the gel.

Foam Fluids

Foam fluids are created by dispersing gas, usually nitrogen, in a liquid. To initiate the dispersion, a surfactant is normally used as a foaming agent.

Because foams have high viscosity and low fluid leakoff properties, they can carry proppant further out into the formation than gel fracturing fluids.

Foam quality is the volumetric ratio of the gas to the total volume of foam at downhole conditions. A 75 quality foam contains 75% gas by volume at downhole temperature and pressure.

Foams used for fracturing typically range from 65-85 quality. Foam fracturing treatments at the Rock Creek project have used 75 quality foam. Higher quality foam provides greater viscosity, but also may increase pump pressure and limit maximum sand concentration.

Foams with a quality less than 52 have a much lower viscosity than higher quality foams and thus do not function as effectively as high viscosity fluids. Foams with a quality less than 52 are usually unstable.

Foams have several advantages over non-foam treatments:

❖ Low liquid content of foam results in a lower hydrostatic head, which enhances well cleanup.

❖ Excellent fluid loss control eliminates the need for fluid loss additives, which reduces impairment of fracture conductiv-ity.

❖ Excellent capability to support proppants, which results in more uniform distribution of proppant throughout the frac-ture.

❖ Energy from the gas in the foam helps to recover treating fluids from the reservoir.

❖ Formations that have been de-watered can be treated without fear of re-saturating the formation.

Though foams offer the highest potential for minimizing dam-age to the coal, you still should carefully consider the polymer used for the aqueous phase as well as the foaming surfactant.

Select a polymer and foamer that is least damaging to the coal.

Many foamers will not work with coal because they adsorb onto the coal. Such foamers may reduce formation permeabil-ity. Select a foamer that will ensure 100% gas entrainment and maximum viscosity and proppant transport characteris-tics.

Biocides eliminate surface degradation of the polymers in the fluid tanks and stop the growth of anaerobic bacteria in the formation.

Breakers enable viscous fracturing fluids to be controllably de-graded to a thin, low viscosity fluid. The two types of breaker systems currently used are enzymes and catalyzed oxidizers. It is very important to select the appropriate breaker and breaker con-centration. No matter how good the proppant transport characteris-tics of the fracturing fluid, they can be completely negated by using excessive breaker concentrations.

Buffers control the pH of the fracturing fluid for the crosslinker and breaker systems and also accelerate or slow down the hydration of certain polymers.

Surfactants lower the surface tension of water in the fracturing In addition to selecting the proper fracturing fluid, you should also carefully consider the numerous fluid additives available to maintain and enhance the properties of the fracturing fluid. Before using an additive, make sure you fully understand its purpose and limitations as well as its compatibility with other fracturing fluids and with formation fluids. Check with service company representatives for complete information on any additives you use.

Fluid additives are available to perform a wide range of functions.

Some of the additives commonly used in fracturing coalbed methane wells are described below: