Fracture fluids in flux
  from: Offshore Engineer
  by: Rick von Flatern
  Wednesday, March 05, 2003

At the sharp end of well fracturing technology is a balancing act between the need for efficient proppant carrying, high-viscosity fluids and lowviscosity fluids that flow easily from the formation once the job is done. With one leading supplier hailing its new fracture fluid design as radical breakout technology, Rick von Flatern enlists the help of industry experts in reviewing the altered state of the art.

But carrying ability, that is the ability of the fluid to keep proppant in suspension during its tortuous path down hole, out through the perforations and to the end, or tip, of the fracture, is essentially a function of high viscosity. Perversely, good cleanup requires the frac fluid viscosity be nearly that of water so it may efficiently flow back to the surface and out from between the sand grains.

Among experts, the success of this balancing act is defined in terms of ‘effective fracture length’. The optimum effective fracture length is not just a function of width and length but also of good conductivity through the proppant and at the formation face. ‘There are two sides to effective frac length,’ says Schlumberger well service stimulation advisor Ernie Brown. ‘One is actually placing the proppant deep in the formation. The other side is how well your fluids clean up.’

Historically, creating a fluid capable of switching between these conditions as required is done by chemically crosslinking a base fracture fluid’s constituent polymers. Then, once the sand is placed in the rock fracture breakers, chemicals activated as a function of time or temperature, break the links between the polymers. Theoretically, the viscosity of the ‘broken’ gel approaches that of water, the sand ‘falls out’ and is deposited in the fracture. The low viscosity fluid flows back to the surface leaving behind a ‘clean’ proppant-packed fracture.

These water-based polymer fluids, with guar as the polymer of choice, have been in use since the 1960s and as the science of fit-for-purpose cross-linking and breaking has been constantly refined and improved, they still dominate the fracture fluid market. Still, long-chain polymers that give the fluids their extreme viscosity can be difficult to ‘break’ efficiently and some amount of unbroken gel is inevitably left in the pore spaces of the fracture proppant.

Very much of this residue is devastating to production rates and ultimate reserves recovery and even relatively small amounts will significantly hinder well performance. Fracturing experts have attacked the problem of making a high viscosity fluid into a low viscosity fluid at just the right moment from essentially two directions. At one end of the spectrum are those who advocate very high concentrations of breaker be added to the mix while in the opposite camp are those who minimize polymer loads. Both strategies have met with success and experts agree each has its place.

But the efficacy of aggressive breaker loading on the one hand or minimal polymer on the other are both subject to the vagaries of any particular well: the caveat concerning effective frac length that is heard consistently around the industry is ‘when the job is properly designed’. Unexpected temperature ranges or formation fluids for instance, can cause a fluid to badly misbehave during the fracturing operation. In such cases, conductivity can be severely damaged by unbroken gels left in the pore spaces between the proppant on the one hand or the sand may fall out of solution prematurely on the other. In the former instance well performance is less than optimal; in the latter the desired fracture length or height is never realized and again production will be below the formation’s true potential.

Mixing it up
In their quest for the proper mix of proppant, breaker and polymer, the industry has also created systems that are polymer and breaker free. Proponents of these surfactant-based systems say that since polymer residue is the enemy of clean up, removing polymer is a logical way to solve the problem.

Taking another tack and the latest entry in the fracture fluid market is Halliburton’s MicroPolymer (HMP) system that, by virtue of being what the company literature calls a pseudo-polymer, claims the carrying ability of high viscosity polymers with the certainty of efficient clean up since it is not dependent on breaker chemistry to revert to very low viscosity once the sand has been deposited. The term ‘pseudo-polymer’ refers to the fact it is actually a series of linked, short metal ions that behave in many ways like polymers under certain conditions.

Halliburton claims for the new product when compared to conventional polymerand surfactant-based systems are considerable. Unveiling the product in Houston recently, Halliburton said it offered a number of improvements over ‘conventional polymer- and surfactantbased fluids’, including significant reductions in treatment volumes, pump time and pump rates with ‘fluid recovery up to 95%’. But what is certain to raise industry eyebrows is the claim HMP has resulted in ‘effective frac lengths increased by up to four or five times normal’.

‘What is going on is, if you’ve got the same volume of HMP that you would of conventional fracture fluid, you will get bigger and longer fractures compared to [traditional] gels,’ explains Lyle Lehman, frac/acid product manager for Halliburton’s production enhancement group. ‘If you engineer your fracture to be the same length (as with other fluids), you will get four to five times the conductivity out of it because it cleans up so well.’

The micropolymer in HMP’s full name refers to the gelling material that is, according to company literature, ‘25 to 30 times smaller than conventional polymer material’. The fluid develops viscosity by linking and ‘de-linking’ these small polymer chains based on pH, eliminating the need for breakers. Once the material is in place, the lower pH characteristic of hydrocarbon-bearing formations causes the polymers to break apart, reducing the fluid’s viscosity to that of water.

‘Instead of breaking the gel we really just de-link it,’ says Lehman. ‘Instead of having a guar molecule that is relatively long, that you have to break, [HMP] is already, in a physical sense, broken. We tie them together and when it quits being linked together it flows out very easily.’

All fracture operations are engineered with a certain amount of proppant-laden fluid pumped at the end of the job and which will never enter the wellbore. Since HMP requires contact with the formation in order to lower its pH and de-link, an encapsulated breaker designed to raise pH may be added in this ‘tail’ section to allow it to be easily flowed back to the surface.

While Halliburton’s approach to good fracture clean up is to create a fluid not dependent on breaker efficiency to reduce the viscosity throughout the fluid pack, Schlumberger and Baker Oil Tools have for some time opted to simply remove the offending polymers altogether.

‘One of the main directions we have gone in is to eliminate any possible damage we could have related to polymers, regardless of size structure or what they are cross-linked with,’ notes Schlumberger’s Brown. ‘Our family of ClearFrac fluids has been commercial for about five years now and at this point it is a very well proven fluid so I see no reason to deviate from working along those lines when we can completely remove the polymer rather than working on the different types.’

Critics have claimed that the absence of polymer reduces the efficiency of surfactant-based fluids in two ways: their relatively low viscosity makes them a poor proppant transport medium and since they do not form a filter cake they lack leak off control.

But, says Brown, history does not support such assertions and the fact the annular volume of surfactant-based fluids sold has continued to grow each year is certainly evidence that the fluids are working. ‘ClearFrac is a premium frac fluid and is probably in the range of 12- 14% of all the jobs we pump,’ he explains. ‘If we were screening them out (prematurely dropping proppant from solution) for the past five years we would not be getting them back and growing the volume of fluid we are pumping.’

The charge that their relatively low viscosity makes surfactants poor proppant carriers, say advocates, is disingenuous since surfactants possess other properties that work to keep the sand in solution from surface to formation. ‘The carrying capability is the viscoelastic nature of the fluid itself,’ observes Brown. ‘We have done proppant flow tests in slots that are several feet high and tens of feet long to measure how fast the proppant drops and at viscosities of less than 50 centipoise at 170 reciprocal seconds, almost a linear frac fluid for most conditions, we get absolutely perfect proppant transport. It is not just simple Newtonian viscosity. Properly mixed it is our best proppant transport.’

Likewise, while conceding surfactants do not create a filter cake, Brown says leak off control depends instead on creating the right fluid for the right formation permeability and in-situ fluids. In rock of less than 10 millidarcies for instance, he says, its leak off characteristics can be controlled to a degree to rival any filter cake. That is not to say, he insists, that consideration of surfactants should be eliminated by the presence of a high permeability environment.

‘We do use [surfactants] in higher perm applications and we still use it offshore but we have to design it and decide if its leak off characteristics are going to be a benefit or not. You have to know when to apply the system.’

Indeed, Baker Oil Tools product line manager for fluid pumping systems and sand control, Rudy deGrood, argues that the lack of filter cake formation is a plus for surfactants like his company’s SurFraq line, particularly in offshore applications where gravel packing is the sand control method of choice.

‘Surfactant-based fluids do not form a filter cake and so they enhance production,’ says deGrood. ‘They are excellent for packing off the casing-screen annulus in a frac pack and in conventional gravel packs. They are a super clean fluid and can be used with seawater, brines, calcium chloride, sodium chloride up to 14.5 pounds per gallon so are ideally suited for frac packs and gravel packs up to 250°F.’

Power struggle
Pumping traditional proppant-laden fracture fluids requires enormous amounts of horsepower, a demand from which operators, particularly offshore, have long sought relief. According to Halliburton’s Lehman, HMP’s carrying capacity and leak off efficiencies give it an edge in that respect by requiring about one-third less horsepower per job than existing systems.

Since it is cross-linked at the surface, HMP must be forced through surface equipment, tubing, perforations and the newly created fracture. That would seem to make lower horsepower demands counterintuitive, the assumption being that highly viscous fluids will create great friction pressures for pumps to overcome. But, says Lehman, the fact it so efficiently suspends proppant means it can be pumped at considerably lower speeds.

‘If you were pumping [a conventional polymer-based] system at 60 barrels per minute you would get the same efficiency easily at 40bbl/min with HMP,’ he explains. ‘It is just that much more efficient in carrying capacity and leak off.’

As Don Weinheimer, global business development and marketing manager of Halliburton’s production enhancement group, explains, HMP maintains its carrying efficiency through the critical operational time when the fluid is being pushed through the fracture. Often in the past, as the breakers have begun to react to time and formation temperature, fluid viscosity has dropped forcing pumps to speed up in an attempt top get the sand as far into the formation as possible before a screen out occurred.

‘Essentially during the frac period the viscosity profile (for HMP) is flat,’ he says. ‘One of the things the industry has done is to keep cutting out polymer to reduce gel damage but as a result of that you keep reducing the gel’s ability to transport proppant and that is the most important thing you do. Since gel clean up is so great with micropolymer and the fact it does not degrade we can continue to carry the proppant and when we shut down [the pumps], the system essentially unzips and flows back out.’

Baker’s deGrood says his company controls horsepower demands while using its polymer-based systems with two crosslinking agents that are activated at different spots along the fracture fluid’s path from surface to fracture. ‘What we typically do is use a surface cross-link system that is sufficient to carry the proppants at the concentration the job was designed for through the surface equipment and downhole but with minimum total viscosity for minimum friction pressure and therefore lower pump requirements to get the fluid to the formation,’ explains deGrood. ‘Then the secondary cross-linker is time and temperature activated so when the fluid turns the corner it kicks in to increase viscosity ten times. It is very fast and designed specifically for the length of the fracture to get the necessary viscosity through the fracture.’

Paying the pumper
By creating a polymer-based gel that reduces to the viscosity of water without breaker being added, it is possible Halliburton has introduced an entirely new order of fracture fluids. The company’s claims that the gel, since it is de-linked reliably by its environment rather than subject to the vagaries of chemical additives, would flow from the tip as readily as from anywhere else along the fracture seems plausible on its face and would by definition significantly increase effective frac length compared to traditional systems.

But nothing new comes without a price and today even the major operators are loathe to let loose of any more money than absolutely necessary. As a result, innovation has been a hard sell and service companies have learned to be careful how they handle customer questions about cost. Like many things technical, agree Lehman and Weinheimer, answering such cost questions about HMP with a simple dollar amount can be misleading.

‘It is obviously an expensive fluid to make, expensive compared to other fluids,’ says Weinheimer. ‘But we have seen, in virtually every case where we have run it, better productivity. We have seen where the client has spent 50% more for his treatment but has paid for that in 90 days and we have histories where client return on investment has been outstanding.’

The analogy Weinheimer uses to explain how HMP costs should be viewed is that of mutual funds. Some investors, he says, look only at front-end load fees and then choose their investment based on which one is lowest without checking the fund’s performance history.

‘We challenge our client to look at the investment up front and realize we can give a much greater return if the appropriate engineering and design is done,’ he points out. ‘The treatment itself becomes cheap when you look at the returns. If you compare treatment return to (other systems’) treatment return, then it becomes the cheaper way to go.’

Schlumberger’s Ernie Brown echoes that sentiment when discussing the cost of surfactants whose initial costs also tend to exceed that of traditional polymer-based fluids. ‘We have cost ranges depending on the application,’ he says. ‘What it comes down to is how you design the system. A properly designed system using the surfactant technology almost always will be competitive with conventional systems.’ Also, since they are not heavy polymer-like gels, surfactant based fluids are more easily pumped through smaller tubulars saving horsepower and, says Schlumberger engineer Leo Burdylo, can be pumped through coiled tubing which potentially offers enormous savings. ‘Friction pressure down smaller tubulars with a surfactant-based system will be less than with a polymer-based system,’ he says. ‘That is why it is possible to fracture through coiled tubing which has a lot of advantages including not needing a workover rig when going into an existing well.’

HMP may also, in the right circumstances, offer a unique cost-saving advantage because unlike any other fracture fluid system on the market, it is reusable. That is because it can be ‘delinked’ and ‘re-linked’ simply, unlike traditional gels that once ‘broken’ cannot be restored.

‘It is the only frac fluid on the planet that can be used again and again,’ maintains Lehman, who reports the same batch of HMP, with some additions for loss, was used on seven frac jobs in Texas recently. ‘All you have to do is revitalize it, re-link it, and you are ready to go.’

In every sector of the upstream oil industry innovations come and go with a startling regularity. Many fulfill their early promise to significantly improve or at least change the way any particular service is performed. Others, for any number of reasons, fall by the wayside and most fall somewhere in between, often becoming a niche tool. Only time will tell into which category Halliburton’s seemingly revolutionary frac fluid falls. OE