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Life of the Well 5: Stimulation

This entry is part 5 of 5 in the series Life of the Well

Customers may choose to stimulate wells either because previous wells in a field have needed it, or because they have run production surveys that suggest that a well may produce at a faster rate after stimulation techniques. Two of the most common stimulation techniques are acidizing and hydraulic fracturing.

Stimulation can be said to be all about permeability. Permeability is the ability of a fluid to flow through rock, in our case. This is contrasted with porosity, which is the spaces between particles of a rock. A paper towel tube full of marbles has both excellent permeability and high porosity. Water poured in the top falls right through and out the bottom, demonstrating high permeability. The roundness of the marbles creates a lot of space between them, showing the highest amount of porous volume possible for a single shape—around 30%. If a rock has high porosity but low permeability, it can hold a lot, but it can’t let go of it.

Sometimes rock is naturally impermeable, like the Barnett shale in north Texas. Sometimes things we do can reduce permeability. Drilling mud is designed to seep into the rock a little bit and stop. This plugging of a rock’s permeability is great for drilling, because the drilling mud isn’t lost all the way into the rock, but it’s bad for production, because oil and gas can’t come back through after the drilling is done. Cement can also plug up the rock. A perforation charge may not burn cleanly, and residue can also cut into permeability. The damage of a rock’s permeability around a wellbore is called skin. The less skin, the less drastic we need to be in stimulating the well.

Acidizing

Depending on the rock’s mineral content, acidizing can be a great way of creating permeability through originally stubborn rock. An acid is pumped down the casing and out the perforations. The acid may be designed to dissolve the drilling mud that has seeped into the rock, or it may be designed to dissolve the rock itself.

Most acidizing treatments are on a smaller scale, using one truck that carries both a 1000-gallon tank and a high-pressure pump. The acid is diluted from raw acid and mixed at the camp with a chemical that keeps the acid from eating the metal tank. The inhibitor is only good for 1 or 2 days, so it’s best to mix it and go to the job site.

Hydrochloric acid is used most often in acidizing, in 15% and 7.5% concentrations. We are ever mindful of the “add acid to water, not water to acid” admonition.

Hydrofluoric acid, often in combination with hydrochloric, is used to acidize sandstone. HF is considered “weak” by disassociation standard, but it’s nasty enough to etch glass.

HCl is not a good idea for formations that contain iron compounds. The iron will join with the chloride and make ferric chloride (FeCl2). Less soluble than rust (Fe2O3), ferric chloride can choke a well and plug up the permeability. This can be remedied somewhat by adding citric acid to the mix. The iron is sequestered into a chelate, making it soluble in water.

Sometimes in a well, some perforations will produce petroleum but others won’t. We employ a technique called “balling off” to bring the weaker producers up. While acid is being pumped down the hole, rubber balls are dropped into the acid and pumped down to the perforations. Because the higher performance perforations will accept more fluid, the balls are slammed into the better holes, shutting off the good holes. Acid then goes into the bad holes, cleaning them up and increasing their production.

When acid is pumped at low rates, under 6 barrels (1 bbl = 42 gal) per minute, we call it matrix acidizing. If it’s pumped high enough to break rock, it’s called fracture acidizing. Fracture acidizing combines the stimulating effects of acidizing with the sheer power of hydraulic fracturing.

Hydraulic Fracturing

Hydraulic fracturing is the act of using a water hammer to break rock underground and increase permeability. Fluid is pumped from the surface, filling up the casing and forcing through the perforations. The perforation is like a pilot hole that the fluid presses on, splitting the rock and creating a fracture.

One perforation can start a fracture, but we perforate sometimes 50 to 200 feet of pipe. The little fractures from each hole join into two large fractures that extend in opposite directions away from the well, like in this picture.

Tens of thousands of gallons of fluid are pumped down the well and into the fracture. In addition to more fluid, a higher pumping rate produces a bigger fracture. The Barnett shale jobs I was on would last for 8 hours, pumping 80 barrels per minute. The highest rate job was 200 bpm and lasted just 20 minutes. :) Our field camp could muster its equipment and that of nearby camps to put together frac jobs of 300 bpm. Pump pressures in normal fracturing vary between 5000 and 8000 psi, but we can go higher than 15000 psi with the right equipment.

Once the rock is filled with fluid and cracked, we need something to keep the fracture open. If pumping is stopped, the rock will just close back on itself, and we haven’t done any good. In shallower wells, we put sand in the fluid. The sand goes into the crack and stays while the crack is trying to close. In deeper wells, usually below 8000′, the rock’s closing can crush normal sand. In those high pressure cases we use man-made ceramic and bauxite proppants. Sand is quite permeable; you can pour water through it easily. When the fracture closes and keeps the sand in place, the permeable sand allows petroleum to flow from the rock, through the sand, and into the casing more quickly.

If you’ve ever put sand in water, you’ll notice that the sand settles out quickly. Sand and just water doesn’t pump very well. We have to put something in the water to carry the sand through the pumps, down the hole, and into the fracture. Some of Halliburton’s competition prefers to use surfactants to carry the sand, but soapy water doesn’t have the viscosity necessary to carry a lot of sand. We use guar. Guar is a natural thickening agent in its own right, but we add chemicals that link multiple guar molecules together in long polymer chains. The fluid can get so thick that if you can pour half of it out of a cup and turn the cup back vertically, the fluid pulls itself back into the cup.

So, we pump thick, nasty fluid full of sand down a hole thousands of feet deep into an opening fracture. The job is still not finished. Now that the sand is in the fracture, we don’t need the fluid to be thick anymore. At the same time we add blend sand, water, guar, and crosslinker, we also add a chemical called a breaker. At lower temperatures, enzymes slowly chew up the guar, keeping our viscosity in the beginning but eventually causing it to lose viscosity and flow back out of the well. At higher temperatures, our poor enzymes get cooked, so we use oxidizers like sodium perchlorate and sodium persulfate.

After the breakers disassemble the polymer molecules, the fluid returns to a thin fluid that flows back out of the well quite easily. Soon after the fracture fluid leaves, the natural fluids in the rock begin to come out.

There are several types of hydraulic fracturing:

Conventional Fracturing
Conventional fracturing consists of what I’ve described as above. Water-based fluids are common in conventional fracturing, but we can also fracture with No. 2 diesel. The diesel-based fracturing fluids are ideal for formations that swell with water, but as you can imagine they pose a significant fire hazard.
Fracture Acidizing
Very much like conventional fracturing, but before the crosslinked, sand-laden fluid is pumped, acid (usually hydrochloric) is pumped to dissolve rock as the fracture grows, providing a double benefit.
Foam Fracturing
Some of our fracturing treatments replace some of the fluid with gas. Less fluid means less that leaks into the rock during the treatment. The injected gas also helps petroleum come out of the rock when it doesn’t get a good push from the formation’s natural pressure. We can inject nitrogen gas into the fracturing fluid, or we can pump liquid carbon dioxide which vaporizes and creates carbon dioxide gas. Fracturing with nitrogen allows us to be selective in our crosslink packages. Nitrogen is inert and doesn’t react with our chemicals. Carbon dioxide foam fracturing lowers the pH of the fluid as CO2 dissolves in the fluid. This keeps water-sensitive formations from swelling, but it limits what chemicals we can use with it.

Between the unique fluid chemistry, high-pressure pumping, and computer modeling of fracture treatments, Halliburton has turned stimulation into its most profitable service. After a formation is stimulated, other zones may be perforated and stimulated. Once the customer is finished with all the desired zones, tubing and tools will be installed in the well, and the well is put on production. This is called completing the well.

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One Comment

  1. Dan says:

    Got an email comment from RandomDan:

    Almost nobody I know uses the gel fracs, but are all going to slick water fracs (KCl water). It’s cheaper and yielding better results for the operators. From what I understand, the fractures are much more horizontal and allow the user to drain the reservoir more extensively than with the gel fracs.

    Well my personal experience is about 8 years old. :)

    Also, you said the fractures were more horizontal. How shallow are these wells?