Frac Diverting FAQs

A frequent question that comes up is "Doesn’t XXXXX have this patented?” 

Using polylactic acid and other polyester materials as diverting agent was addressed in patents issued in the early to mid 1980’s. These patents have expired. The methods and materials are now no longer enforceable. In legalese, there is now a "freedom to practice” these methods.

The 4,387,769 patent contains the following abstract and first claim:

Abstract: The present invention relates generally to the composition and method for reducing the permeability of subterranean formations penetrated by a wellbore. The composition of the present invention comprises a wellbore fluid having dispersed therein a fluid loss control agent comprising a polyester polymer which is substantially insoluble in the wellbore fluid. The polymer degrades in the presence of water at an elevated temperature to form small molecules which are soluble in a fluid in the subterranean formation. The method of the present invention comprises reducing the permeability of subterranean formations penetrated by a wellbore by placing the composition of the present invention down the wellbore. 

Claim: 

1. A method for reducing the permeability of a subterranean formation penetrated by a wellbore comprising:

dispersing discrete solid structures comprising a polyester polymer into a wellbore fluid, said polymer being substantially insoluble in said wellbore fluid and degradable in the presence of water at the formation temperature to oligomers which are at least partially soluble in a formation fluid and placing said wellbore fluid containing said structures dispersed therein into said wellbore. 

The 4,526,695 patent contains the following abstract and first claim:

Abstract: The present invention relates generally to the composition and method for reducing the permeability of subterranean formations penetrated by a wellbore. The composition of the present invention comprises a wellbore fluid having dispersed therein a fluid loss control agent comprising a polyester polymer which is substantially insoluble in the wellbore fluid. The polymer degrades in the presence of water at an elevated temperature to form small molecules which are soluble in a fluid in the subterranean formation. The method of the present invention comprises reducing the permeability of subterranean formations penetrated by a wellbore by placing the composition of the present invention down the wellbore.

Claim 1: A wellbore fluid for reducing the permeability of a subterranean formation penetrated by a wellbore comprising a fluid having dispersed therein discrete solid structures of a polymer having the repeating unit: ##STR3## wherein R is H, C.sub.1 to C.sub.4 alkyl and n is sufficiently large to form a solid polymer, said polymer being substantially insoluble in said wellbore fluid and degradable in the presence of water at an elevated temperature to oligomers which are at least partially soluble in oil or water.

What makes a polymer (PLA) biodegradable? 

Polylactic acid is an example of a polyester. A polyester is a polymer made up of many "esters." Water is the chemical that causes these materials to break down to water soluble components. Actually, very little water is required. The water that is between the particles of a tight pack is more than enough to get to a solid-s free state. And any water available will work, even if it is just a fraction of a percent in produced fluids. Chemically, these water degradable plastics are generally in a class of materials called polyesters.

The degradation of a polyester by the process of hydrolysis can be understood by first considering the properties of esters.

An ester is the chemical combination of an alcohol and an acid with the elimination of a water molecule. The water molecule is captured during the manufacturing process such that it can not be recombined with the ester. This process is called esterification. However, if an ester is added to an aqueous fluid, water can gradually react with the ester and split the ester back into an alcohol and an acid. This process has been used in the oil field as a slow release acid for breaking calcium carbonate filtercake and to uncrosslink fracturing fluids.

Some acids, such as the organic acids lactic and glycolic, have both the reactive OH group and the proton (H) in the same molecule. These can be processed to form polyesters as shown in the diagram. Depending on the acid used (or combination of acids), a wide range of degradation rates are possible.

 

Some of the larger organic acids with both groups can actually bend around and form a "cyclic ester" called lactones. Gluconic acid is a good example and its cyclic ester is call gluconolactone (it may be called glucono delta-lactone). 

In the case of lactic acid (not big and flexible enough to form a cycle on its own), two molecules can form a cyclic ester and is called a lactide. In the manufacturing of polylactic acid, the lactide is formed first and then a ring opening step is performed to form the long chain polymer. This is why polylactic acid is often called polylactide. Glycolic acid is similar (glycolide). 

Lactic acid exists in what can be thought of as a right-hand and a left-hand version. If polylactic acid is made up primarily of one version, the material is much more crystalline (since they can form a regular pattern, which is what crystallinity is). If a polylactide is formed with a mixture of both versions the results will be a material that is not crystalline and this is called "amorphous." Crystalline versions are generally stronger and degrade more slowly. 

Combinations of acids can be used and polymers made from these are called co-polymers. By mixing, lactic and glycolic for example, additional changes in properties are possible. 

The chain length can also be varied to give additional properties. 

As you can see, there is a large amount of variations in producing these type materials and it is these variations that allow even "custom" polymers that can be made for certain applications. 

A number of different types of polylactic acid are available from ICO Polymers. They call their polylactic polymer products by the trade name of Ecorene. 

Crystalline Polylactic acid is a fairly tough, temporary material. It is a hard plastic with a compressive strength that can be as high as 12,000 psi (depending on the particular version, in this case a high molecular weight, crystalline version).

At down hole temperatures, the material is only temporarily a solid. Depending on temperature, it will degrade or may melt (again, depending on the version). In the case of degradation, the material may last hours or weeks depending on the temperature.

The biggest application for this material at the current time is as a stage diverter in shale refrac treatments (more on this later). But, given the flexibility in sizing, it can be used as a fluid loss particle or bridging particle. It can also be made in sizes big enough to seal perforation holes. 

Other uses:

Diverting stimulation fluids: Stimulation fluids can be any number of wellbore treatment fluids. Acid is a common treatment fluid, but solvents for waxes, scale inhibitors, fines and clay control, sand consolidation, surfactants, water control and shale swelling are a few of the other type treatments that may benefit from proper placement. For example, it may be desired to place 100 gal of a 15% HCl treatment per foot of perforated interval. The acid will naturally enter the most permeable sections at a higher rate, react with the formation and increase the rate of injection into this more permeable rock.  At best, this is a poor use of acid and at worse it may give no production increase since this section was already open. Having the acid go into only a fraction of the interval is also not consistent with the objective of placing only 100 gal for each foot of interval. So, once a volume equivalent of 100 gal/ft goes into a given portion of the zone, it would be desired that no more treatment fluid enter this section and that a subsequent volume enter a different section of the interval. Diverting materials are used for this purpose. They don’t have to completely seal the interval, but form enough of a barrier where the treatment fluid is significantly redirected. In any case, having the material be temporary is of primary importance. First, to make sure there is no permanent damage and to eliminate the need to pump a cleanup fluid. This same general functionality applies to the other types of treatment fluid mentioned above.

Fluid loss pills and lost circulation: where pills formulated with materials like calcium carbonate or other bridging solids are in common use, the pills used in the pay zone would benefit from the use of material that does not need a subsequent cleanup fluids. All the particle sizing criteria that apply to these fluid systems would apply to ones made from PLA particles. It is likely that the fluid loss additives, such as starch, that are used with these systems would also be required for the PLA particles as well. The exception here would be those versions of PLA that have considerable pliability.

There has been limited, if any, success in placing additional fractures behind existing frac sleeve completions. The flow paths and the interaction with a diverter system is very complex situation with the sleeves. It would not be possible to cover all the possibilities on this page, but we’ll use the following as an example:

In what was originally a perf and plug completion, there will be a number of perforation tunnels for which the diverting particles can enter and block. It may be possible for some of the diverting material to build a node back into the casing, perhaps with a 1 to 2 inch height. If this happens, it is not enough blockage to prevent a frac treatment from getting past this point should there still be an untreated interval downhole. 

In an open hole situation where the fracture intersects the open hole, any node of particles that builds could cover 360o of the fracture intersection with the open hole and build out to the sleeve OD. In this case, the node height is enough to block the annulus between the sleeve and the open hole. 

This situation would be even worse should the original fracture initiate just adjacent to the ports. Once a pack of particles built back to the ports, it is unlikely that any additional fracturing treatments could be placed in that interval.

There are a number of precautions that can be taken with the diverter design to address some of the possible flow restrictions, but the effort will be much greater than that of the perf and plug completions.

It is generally not possible to get reliable information on the fracture widths that are being sealed on near the wellbore. So the following is the procedure used. 

Determine the largest particle your pumping company can readily pump through their equipment. This is usually in the 6 to 8 mesh range. About 15 to 20% of the diverting material will be these larger particles. Once this larger size is given, then a particle size distribution needed to seal on the larger particles is determined. The sizing of the distribution of smaller particles will be provided by Completion Science. The particle distribution will include enough of a smaller range such that the pack can filter out polymers such as guar and friction reducer (or any other organic material that may be in the water supplied). This ability to filter these type materials out of the base fluid gives the system its final seal.

Polylactic acid – This material is compatible with just about all fluid systems including water, brine, slick water, gelled fluids and acid. The service life (degradation rate) will be similar for most aqueous based fluids. The service life will be shorter in acid since acid accelerates the degradation rate. However, since acid jobs are generally pumped in a matter of hours, the service life will still be long enough for this material to function. 

Benzoic acid – This well known diverting material is also compatible with most aqueous fluids including acid. The service life is not shortened in acid. Benzoic should not be used in high pH fluids.

When pumping polylactic acid as a diverter in shale fracturing, most treatments will only be a few hundred pounds per stage. This can easily be handled by adding the material directly into the blender tub by cutting sacks. Given the concentrations and rates recommended, the rate of addition will be in the one to two sacks per minute. 

In the case of larger stages, the material can be added using dry add feeders (or up the sand screws). Keep in mind that the specific gravity for polylactic acid is 1.25 and adjust the calibration factor accordingly.

As covered in "What make a polymer biodegradable,” there are a number of characteristics that can be changed to get different degradation rates for polymers such as polylactic acid and the other degradable polyesters. These include degree of crystallinity, molecular weight, co-polymerization and additives. The chart below shows the degradation rate of what might be considered a mid-temperature range PLA and a high temperature range PLA.

The chart below shows three different variations of the high temperature versions of PLA.

Note that for all degradation testing, the comparisons are only valid for a particular particle size distribution. The degradation rate is very dependent on particle size. For the testing shown in this chart, the materials were sieved to a very narrow 40/45 mesh range.

There are literally dozens of variations in the types of polymers that are manufactured. Talk with us about what you are looking for and we will match your requirements with the most economically attractive alternative.

Overcoming the distance coil tubing can reach for drilling out plugs – Given that there is a finite distance that coil tubing can be used to drill out frac plugs, the laterals can be drilled beyond this distance and any stages installed further out can be diverted with polylactic acid to frac each perforated interval in this extended interval. Install the perf cluster in this interval and plan on a stage of diverter for each. Once these have been treated, a plug can be set and the rest of the lateral completed with a normal plug and perf operation.

Reducing the number of plugs used – Two or more perforation clusters can be created and diverters used in this interval. A plug can be installed and the process repeated to reduce the number of plugs used. In the case where three clusters are installed, the number of plugs used is reduced by 66%.

Casing hung up before reaching total depth – pumped the planned number of stages in the open hole interval and use diverter stages in between each stage. 

Parted casing or partially collapsed casing – In the case where guns can be run, but plugs cannot, plan to divert the stages instead of the plugs.

Initial Information needed for a shale diverter treatment design.

Is this a new completion (replacing plugs) or a recompletion?

What is the bottom hole static temperature?

                Optional: Do you have cooldown modeling?

What is the service life time needed (this may be the days or hours of pumping)?

What is the largest particle you feel comfortable pumping (usually 4 mesh > x > 10 mesh)?

How much proppant has been pumped through the perforations?

How many stages are planned?

Number of perforations per stage?

What percent of perforations are open and taking treatment?

What magnitude of pressure increase are you expecting?

Will the fluid targeted to carry the diverter be gelled or have friction reducer?

Are you planning on running a surfactant?

Do you want lab tests performed at your conditions?

Do you need samples for lab testing?

Will someone be taking the role of "product champion?”

When is your first application scheduled (leadtime)?

Will new perforated intervals be added to existing wellbore?

If treatment is needed due to casing issues, please describe (partially collapsed, casing stuck before td etc)?

What is the design process for sizing the particles used in diverting treatments in the shale formations?

The simple answer to this is pump the biggest particles you can and size the other particles to seal on and around these. This may seem over simplistic, but it requires a good amount of engineering understanding to get there. There are a number of oilfield related applications that involve sizing particles to bridge or seal. Some good examples are sizing the bridging particles in a drill-in fluid or sizing diverting materials to bridge on a perforation. 

Extensive research has been conducted in the past to answer the question about bridging on perforations or pores. A classic is "Particle Transport Through Perforations,” SPE 7006, Gruesbeck, C., Exxon Production Research Co., Collins, R.E., U. of Houston. See Figure 6 of that paper for rules on sizing bridging particles relative to the perforation diameter and the effects of particle slurry concentration. (Note: We are requesting permission from SPE for use of the graphs discussed in this page. Check back at a later date)

The take home message from this chart is that at low concentrations, a particle nearly as big as the perforation may be needed. As the concentration increases, a bridge could form with particles that are actually significantly smaller than the perforation hole. In fact particles that are only 1/5 the size of the perf would be expected to form a bridge at concentrations of 6 lbs/gal or higher (with sand). 

So that’s all well and good, but what about sealing or bridging on a fracture or slot inlet. We will start with a slot of sufficient length such that end effects can be ruled out (in engineering terms, an infinite slot). If we took this case and went to the laboratory with the expectation of getting results similar to the above, we would be sorely disappointed. After many frustrating attempts, we would have to conclude that the only predictable and stable results are those with particles at least as big as the slot. 

So, let’s go back to the round hole case and work our way toward a slot. The simplest case would be to make a "hole” that is a very short slot, basically, a square hole. Testing on this would give us results not too much different from the above perforation example. We could then move to a slot that is twice as long as wide. Then we could double the length, then double it again. Similar testing to this was carried out and reported in SPE 126310 "Correlating Flowing Time and Conditions for Plugging of Rectangular Openings, Natural Fractures, and Slotted Liners by Suspended Particles,” T.V. Tran, F. Civan, Univ. of Oklahoma; I. Robb, Halliburton. See Figure 6 from that paper.

With a bit of extrapolation, one could generalize this by saying that in a slot twice as long as wide, it would take about 3 or 4 particles to bridge the width (bigger particles, than the square). In a slot 4 times as long as wide, we would start noticing that we are now needing particles big enough that two of them bridge the slot. As we kept getting the aspect ratio (length to width) bigger it would get harder and harder to get predictable results unless we had particles as big as the slot width itself. We can see from this that the "end” effects are important. Having an "end” of the slot to help hold particles in place greatly improves the conditions of bridging. An analogy to this would be how easy it would be to set a tripod over a hole, but difficult to set it over a crack if there is no place for the third leg to sit. The additional dimension is critical for bridge stability. There are other factors which also contribute to the instability and they are covered well in SPE 67298, "Proppant Holdup, Bridging, and Screen-out Behavior in Naturally Fractured Reservoirs,” R.D Barree, M.W. Conway. The conclusion of this paper regarding stable bridges across a fracture is that there are some additional factors involving fluid flow that enter the discussion (warning, topics like Bernoulli’s equation are going to come up).

Once the larger particles used for fracturing diverting are sized, sizing the remaining particles becomes simple. Note the relationship below between three adjacent particles and the resulting "pore throat.” 

The pore throat is about 1/6 the size of the particles. We could choose something just slightly larger than this, say 1/5 to ensure quick bridging (actually plugging). We could even add particles that are 1/5 of these smaller particles we just added as well. The motivation for this is to get down to small enough pore throats to get filtration in addition to bridging. The pack now is capable of filtering out polymers (guar or friction reducer) or other small, soft material (let’s face it, the water we use for fracturing is not hospital clean). This filtration that takes place gives a very good, final seal to the pack. 

The smaller particles are generally not sized in discrete steps but are taken from the grinding process with a natural particle size distribution that includes the sizes discussed. 

So, what do we know about the size of the fractures near the wellbore in naturally fractured rock like shale? Well, not much. Not only do we not know how wide the fractures are, we don’t know how many are intersecting the perforation tunnels. In fact, there really isn’t a perforation tunnel left after the erosion that has taken place outside the casing after a fracturing treatment was placed. There is some type of eroded cavity there now. 

Consider these statements:

1. A sand slurry is erosive to rock (and cement and steel).

2. A large amount of sand slurry pumped eroded out a cavity downstream of the perforation (jet orifice). 

3. Looking at shale cores, we see it is broken up in chunks.

4. The eroded cavity probably intersects one or more of these chunks. 

5. The fracture(s) initiated between these chunks.

6. At the end of pumping, the fractures are probably not 100% sand filled. 

Can we be sure about statement 6? If the fracture were completely sand filled, we could pump a diverter that had particles only big enough to seal on the sand pore throats. If you try this, it will fail miserably. So, there is something other than 100% sand filled fractures near the wellbore.

But how wide are they? We don’t know, but we could just pump the biggest particle we can get through the pumps and see what happens (or we could rig up some kind of downstream injector if the pumpable particles aren’t big enough, but that is not an easy solution to get to). And that is basically how we got to where we are. There were attempts to apply engineering, but it was soon obvious that the amount of engineering effort that would have to be expended to understand such a complex system would not be worth the expense. A field trial was cheaper and faster.

It may not be possible to use the same methods in other type formations as is used to refrac shale formations. We are already sizing the bigger particles in the diverters for the shale formations as big as possible but still able to get through frac pumping units. In sandstone and carbonates, the fractures are likely conventional bi-wing shaped. Since a single fracture intersects the wellbore, its width is likely going to exceed the diameter of the larger particles in the diverter system. 

If you have modeled your situation carefully and are sure the larger particles are in fact  big enough to bridge the fracture widths (perhaps with stopping pumping and waiting for closure), then we can discuss the use of particulates for your application.

If you have a unique material that is currently (or soon) being manufactured in an industry outside the oilfield and would like to know if it could have oilfield applications, you should answer these simple questions:

Is it temporary in nature? To meet this requirement, it may very slowly dissolve in water, oil or gas, degrade by hydrolysis, sublime, chemically decompose, have an activator etc.

What form is it physically? It might resemble metal, glass, plastic, putty, foam rubber or a thick liquid.

Is it safe to handle? If it is somewhere between calcium carbonate and hydrochloric acid, it may be suitable for oilfield applications.

What is the cost? The volume potential in the oilfield is going to depend on price. Sand and calcium carbonate are examples of cheap materials (although not temporary) that are used by the millions of pounds. Enzymes are used in certain oilfield applications and may cost as much as $100/lb, but their use is limited to only the most high-value of applications.

What is the shelf-life? Can it withstand months in a warehouse in West Texas in the heat of summer or the cold winters of North Dakota?

What sizes can it be produced in? A material that is precipitated from solution is going to have a much more limited size range than something that can be injection molded.