Tech Talk - the difference between fracking and acidizing a well

It turns out that in the end I wrote some 929 posts on The Oil Drum, over the course of its eight-year life, 92 of them in the past two years. The posts covered the gamut from how coal mines work, to some of the innovative work being done in Saudi Arabia to extend the life of their reservoirs - sometimes straying a little from a tight focus on fossil fuel extraction but rarely for long. As I noted in last week’s post (which ran a week later on The Oil Drum as my swan song there) the audience that the site brought far exceeded any that I had during the totality of the students that sat in my classes over 40-years of teaching (a number in the low thousands).

My hope in writing was to provide a little background to some of the stories that made the news and to put some of the developments in context, so that readers might better understand. One of the most useful sources for this was always Leanan’s Drumbeat, and as this now too fades into an archive, let me pick an example from the penultimate Drumbeat as the basis for this week’s post.

The story comes from the San Francisco Chronicle and runs under the headline “Acidizing could rival fracking in Monterey Shale.” The précis for the story reads as follows:

Fracking hasn’t unleashed an oil production boom in California, at least not yet. Could acid?

Companies trying to pry oil from a vast shale formation beneath Central California have been pumping powerful acids underground to dissolve the rock and free the petroleum within.

And there are hints that the process, known as “acidizing” a well, may work better than hydraulic fracturing in California’s Monterey Shale, estimated to hold 15.4 billion barrels of oil.

There are two parts to this story that are worthy of comment. The first is to discuss the comparison between acidizing and fracking a well, while the second is the potential for an expansion of production from the Monterey Shale. (But I will cover that later topic in the next Tech Talk).

The process of fracking a well has been well discussed in the past couple of years as the success of the technique has helped make oil and gas deposits found in shale deposits more profitable and viably productive. During the time that I was writing posts on the technology of oil and gas well development, there was one post that dealt with fracking specifically. It was followed by a post last year in which acidizing was covered as part of the work that Saudi Aramco were using to improve the production from the Berri and Ghawar oilfields.

Since these posts are now a little old and separate let me repost just a couple of relevant bits, in part to explain that neither process is quite as dramatic as it was made out to be in the SF Chron article.

Figure 1. Crack growing out from a drilled hole in Plexiglas, the small notch at the top of the hole controlled the direction of the growth of the crack (We put ink in the hole to show how the fluid goes into the crack).

In the above picture you can see that when the hole was pressurized, a crack grew, and ink flowed into the crack, as it formed, but, when the pressure came off, the crack closed and most of the ink was forced back out of the crack. (We created the pressure by firing an air rifle pellet into the hole).

So if we are going to have a useful crack we need to have it open after we take the pressure back off – after all we need to get the fluid back out of the well, so that the gas can pass up the well for collection.

Now it is not quite as easy to grow the crack, or prop it open as I may have suggested earlier, and to explain some of the issues in a little more detail I am going to use an example and some details from the Modern Shale Gas Primer .

When you decide to frac the well, and each well is different, as is just about every location, so there is a significant amount of preparation and knowledge required to work out the procedure required at that particular point. Bear in mind that the crack that you are going to have to grow needs to stay in the shale layer, and not go out beyond it into the surrounding rock. One of the reasons for this is, apart from giving the gas a path to the well, if it goes outside the reservoir rock then the gas can escape, or, alternately, other fluids can gain access to the well. This is particularly true of the Barnett where the rock immediately below it, the Ellenberger limestones, can hold a lot of water that can muck up the gas recovery if it gets into the fractures. (Given this degree of control and the large distance below the ground to the reservoir rock, this is why a lot of the fears that the frac job will damage the ground water tend to be dramatically overstated).

In the example cited, which is from the Marcellus shale, the treatment of the frac takes a total of 18 steps, and because some of these are fairly similar I am going to go through them in groups. First the hole is treated with an acid, to clean away any remaining debris and mud from the drilling operation and to clean any fractures around the hole, so that they can be used to help the frac grow. After the acid the hole is filled with an initial polymeric fluid, largely water, but containing the “Banana Water” that I referred to in an earlier post. This is a friction reducing agent and will help carry the particles used to hold the crack open into the crack in the first place. The problem with that polymer is that some of the choices available, while good at reducing the friction to help move the particles, aren’t that good at holding the particles in suspension, and the last thing we need is for them to settle out in the bottom of the well, and so in the subsequent steps in the process as the particles (or proppants) are added, there is usually a second polymer in the mix to hold them in suspension.

Once the hole is full of the slickwater (the official term for the first polymer solution) the initial frac is made with a fine sand suspended in the fluid. To keep the crack open all along its length we need sand along the path and the crack gets narrower as it grows deeper. So for the first several stages of the crack growth the fluid is filled with successively greater concentrations of the fine sand, so that, in this way, it can penetrate to the deepest part of the fracture.

In the example cited there are some seven of these sub-stages with the fluid being pumped into the well at some 3,000 gpm but varying the fluid:proppant density to carry more and more of the particles into the fracture. Once these stages have been completed, then the job is finished by pumping an additional eight sub-stages of fluid, with this second set containing a larger size of proppant particles. In this way the area closest to the mouth of the fracture will be held wider apart to make it easier for the gas to escape. As with the first set of sub-stages, the concentration of proppant in the fluid increases as the stages progress. In total, in the example given, some 450,000 lb of proppant was used to make the fracture, together with some 578,000 gallons of water.

Once the fracture is created, then the well is flushed to clean out the different fluids, and make it easier for the gas to get out out of the rock and into the well. (It also removes any loose and ineffective proppant so that it doesn’t later become a nuisance). If you think that this would need a lot of equipment you are right!

Figure 2. Equipment used for hydraulic fracturing a well (Primer)

You may note that, as part of the process for preparing the well for fracturing, the well bore is first cleaned by acidizing the bore to dissolve the fine materials left along the wall and in the nearby cracks and joints of the rock, before the well is pressurized.

The description of acidizing is as follows:

The problem of scale is also that, in the pumping of fluids into the reservoirs, and the flow of oil out, the quantities that are dealt with are significantly larger than in most other countries. Flow levels are required to reach over 10,000 bd, both in oil recovery, and in the relatively precise location of water injection to sustain reservoir pressures. This led Aramco to adopt horizontal well technology, not only for the recovery of oil, but also in the injection wells that are used to inject the seawater.

Horizontal wells in carbonate are prone to well damage around the borehole, due to the drilling process, and this initially limits the flow of fluid through this annulus, or requires a higher driving pressure to inject the water into the formation. In one example it took an injection pressure of 2,350 psi to drive 13,000 bd through an exposed horizontal open hole section some 8,900 ft long. In order to improve the performance of the well it was to be treated with an acid bath to not only remove damaged sections of the wall, but also to eat wormholes into the formation. Where the wells are draining gas it is not that difficult to bullhead the acid into the well where the acid is injected and allowed to fill the well for a couple of hours before being removed. This can be successful in wells where the use of coiled tubing (CT) is limited and flow rates would otherwise not be as high as needed for an effective cleaning. But it requires considerable volumes of acid, and in filling the entire open hole, there is the risk of differential attack along the walls, providing an undesired result. The alternative was to use the smaller diameter of a coiled tubing rig and feed this first to the back of the hole and then inject acid as the coiled tubing was pulling out of hole (POOH). However it is sometimes a little difficult to feed the smaller pipe down the open hole all the way to the back, and the diameter limits the rate at which acid could be injected. Thus there was a debate as to which method would be the best to use.

Aramco have used two ways to get around this problem. The first was to use a down-hole tractor to overcome the frictional forces which were otherwise stalling the placement of the CT by overwhelming the driving force before the tool could reach the back of the hole. The tractor has a small series of wheels that are recessed within the tool while it is fed down the well to the point where it is deployed.

Figure 3. Down-hole coiled tubing tractor (Welltec )

When the CT Well Tractor is initially powered up, the wheel sections are hydraulically extended out of the tool body and activated automatically. Each wheel contains its own independent hydraulic motor, which drives the wheels and provides the forward motion of the CT Well Tractor. . . . . . The modular structure of the drive sections makes it possible to change the traction by reducing or increasing the number of wheels needed to drive the toolstring. The CT Well Tractor 318 can provide a pull of 3,500 lbs, which doubles in tandem configuration. This can further be increased to 10,000 lbs by stacking three CT Well Tractors.

The first major test of this was in the 8,900 horizontal section water injection well I referred to above. That section of the well was divided into 16 sections each of which was treated as follows:

1. First, the treatment interval has to be washed with plain 20 wt% HCl for filter-cake clean up and provide initial wormholes. The main additives to the plain acid are a corrosion inhibitor, surfactant, and friction reducer. Plain acid was used at 10 gal/ft, including additives, resulting in a total acid volume of 77,000 gallons.
2. Plain acid was followed by 20 wt% diesel emulsified acid at 20 gal/ft with a total of 154,000 gallons for the 16 treatment stages. The higher concentration of retarded acid is meant to provide deeper wormholes.
3. To achieve better acid diversion at the end of each pumping stage, viscoelastic surfactant-based (VES) water will be used at 10 gal/ft at a total volume of 7,500 gallons.
4. Finally, water over-flush of 10,000 gallons is to be pumped following the previous 16 treatment stages to break micelles formed by VES. The over-flush contained brine water mixed with 3 vol% of mutual solvent.
The total treatment fluid to be injected in this job is 248,500 gallons; this large acid job is considered one of the biggest stimulation jobs for any well in the Ghawar field.

There were a couple of glitches with running the tool, in that the well had washouts that it took a “flying leap” for the tractor to get past and it was not able to reach the last 3,000 ft of the well, which was bullheaded. Nevertheless after the treatment the flow injection rate for the well was increased from 13,000 barrels of water per day (BWPD) to 28,000 BWPD.

In a consequent test in a multilateral water injection well some 362,700 gallons of treatment fluid were used to acidize a dual lateral horizontal water injection well with a total horizontal interval of 10,335 feet. Prior to the treatment the well required an injection pressure of 2,100 psi to inject 15,000 BWPD into the formation. After the treatment the two laterals were able to inject 30,000 BWPD at 700 psi driving pressure, and at 2,100 psi the wells became capable of deliving 80,000 BWPD. This saved the cost of adding two additional wells in the neighborhood.

Hopefully this should show that there is quite a bit of difference in the techniques and in their purpose down-hole. And while acidizing has some potential for opening existing cracks and passages in a rock it depends on the rock type as to which acid might work best, and how successful it might be.

But I’ll write more on this, and with relevance to the Monterey Shale, next time.

Carbonates, chalk and oilfield subsidence

This is a part of the continuing series of technical talks that I post on Sundays, and which are listed on the right side of the page. Gradually these are getting a little more technical, so I would suggest if you are new to these that you start at the beginning and work your way up.

Having just written about sandstones and permeability, and then about water flooding, I want to go on, this time to talk about carbonate rocks, as the general topic and secondary porosity, with some comments at the end on formations in chalk and the problems that this can bring to places such as Ekofisk. (Added for clarity - when I talk about carbonates I mean calcium carbonate and the related rocks such as limestone, chalk and dolomite, to name but three). I again want to emphasize that, life being what it is, the true situation is often a bit more complex than I describe in this simplistic overview, and that I am very grateful when folk give more specific information about some of their experiences in the field.

When I wrote about sandstones, I mentioned that (as a general rule) carbonates are different to the conditions found with sandstone. For a start the rock itself is much finer grained than a typical sandstone. Even if there were oil in the body of the rock it would be more difficult to get out. Most of the oil is found in what is called secondary porosity. This is the network of fractures and bedding planes that are formed in the rock as it is compressed and moved after it has first been formed. The rock is largely limestone, though it may also be dolomite or related rocks. The rock is usually not a massive, solid rock (such as you might want to build a house or cathedral with).

Exposed limestone

Rather oil will collect where there are spaces in the rock. These can be where there was a coral reef, or a lot of change in rock structure. You can see that sort of thing in some new road cuts

such as this one.

It is easier to explain some of the problems of getting the oil out, if one looks at a road cut that has weathered a bit

Weathered rock wall

You can see how the passage of water has opened the joints and dissolved small holes (or vugs) in the rock. These provide the spaces in the rock into which the oil can move and collect and be trapped. Perhaps it might be easier if I used a simpler sketch of a section through the rock to make the next point.

Section through a fractured rock, showing how the oil is in fractures that the well does not reach.

With the oil painted green, as it fills one crack system, but not them all, the well is just a little bit too far to the left to tap into the major fissure system and get all the oil. If only we could reach out a few feet and hit those cracks! And we can and do.

This is part of the reason that we send down the small explosive shaped charges that not only penetrate through the well case and the concrete, but also extend a hole out into the rock. By driving these perforations out into the crack system in the rock a path can be created from the oil-filled cracks to the well. Those cracks can also be cleaned up a bit (since they often have very small particles of carbonate filling them in the zone around the well) by having an acid pumped down into the completion zone. This acid will also open up some of the finer fissures in the rock so that a free path will develop from the well to the oil-filled cracks.

And so we can begin to produce oil. However after a while, for one of several reasons, the flow from the well will begin to decline. I mentioned last time that the underlying reason will be that the pressure in the reservoir will drop as the oil is withdrawn. But there are other reasons.

If the oil is removed too quickly we can generate, before we need to, a gas cap in the well. Fine rock can be carried through the cracks towards the well, and block the passages. Some of the oil contents, such as the waxes, can settle out of the oil, and fill the holes in the well casing. As the oil flows to the well, underlying water can follow it and cut-off blocks of oil in the rock. And the pressure difference between the oil further away from the well, and the well itself might not be enough to move that more distant oil towards the well. (Are you really sure you want to make this investment ?)

Before I leave Carbonates let me go back to the other kind, where there is a reasonable amount of primary porosity, and where the oil is spread through the rock. This can happen when, for example, the rock is a chalk (another form of calcium carbonate or limestone).

Chalk, somewhat similar to that in which the oil at Ekofisk is found

Chalk poses some different problems in production. Let me illustrate them with an abbreviated history of the Ekofisk field. The field was found in 1969, and started production in 1971. It produced from a fractured chalk that has “high porosity but low permeability.” When it was originally produced the driving force to move the oil to the wells was through pressure depletion of the oil, and in this way they were able to recover between 17 and 18% of the oil in place. In the process, however, there was a relatively unexpected problem.

To explain it let me make a very very simple illustrative example.

Representation of Oil (grey) filling pores in a rock.

Now in the original condition the pressure of the oil in the pores (holes) in the rock above is equal to a significant portion of the the pressure of the overlying rock. At Ekofisk the pore pressure was 7,135 psia at a depth of 10,400 ft. Porosity can be as high as 48%.

But as the oil is drawn off through the well that pressure reduces, and the load transfers to the rock columns that are one either side of the circular pores. (The well pressure was reduced to below 5,000 psi). When the load on these columns becomes higher than the strength of the rock then the pillars will collapse. This helps a little to squeeze some of the oil out, but it also (when it happens over a large enough volume) compresses the entire volume of the rock holding the oil. This can close some of the passage ways to the well (permeability), and make it harder to get the oil out, though that does not appear to have happened. But it also lowers the sea bed, on which some of the recovery oil platforms were standing. That subsidence has been up to 30 ft in places. (The platforms were elevated in 1987) but new platforms were ultimately required that would allow a subsidence of up to 66 ft. (20 meters).

In order to stop the collapse, and also to increase the flow of oil to the wells, a program using water injection at pressure was started in 1987, by injecting 820,000 barrels of water a day, it was anticipated that the field would allow the recovery of about 36% of the oil, and provide an additional 300 million barrels of oil. Current estimates are that it will increase overall recovery to 50% of the oil in place.

There are, however, now some concerns about the dissolution of some of the chalk by the water that is being used for the injection, weakening it further, One of the problems in analysis, as it turns out, has been in disregarding the temperatures at which the extraction is occurring. (For those who go to the reference the exchange rate is roughly 5 kr to the dollar).

From which you will see that there is still lots to talk about. But, as before, if I have glossed over stuff, just ask a question and I (or others who contribute) will be glad to give an answer.