Waterjetting 32d - Cutting with polymer in the water

In the recent past I have written about the use of polymers in high-pressure jets and that they can significantly improve jetting performance, with no additional changes in the power or pump and equipment used in the work. This is because of two different effects that the polymers have. Firstly they reduce turbulence in the flow from the pump to the nozzle, reducing pressure loss and increasing fluid flow, for the same pump power. As a practical consequence since the fluid flow will be greater for the same pump pressure, this will require that a larger orifice diameter be used to handle the greater, or – for the same flow rate and nozzle diameter, the pump can be operated at a lower pressure.

Figure 1. Comparison between a conventional jet and one containing the polymer additive marketed as SUPERWATER. (after Glenn Howells)

This is not immediately apparent, since the jet carrying the polymer appears smaller, but this is due to the second effect of the polymer, which is to tend to glue the water together, so that it is not dispersed as easily by the surrounding fluid – air in this case. In fact, for the same pump pressure and orifice diameter the lower jet will be operating at a higher pressure (since there is less pressure loss in the line) and there will be more water coming out of the polymer-supplied orifice at a higher velocity. But because it is not spreading into the air, it appears smaller.

This will improve the cohesion of the jet as it moves away from the jet, and as noted in an earlier post, this means that the jet will cut to a greater range from the jet, since it maintains the required critical pressure further.

The impact that the more coherent jet has on performance can be seen where the jet is used to cut into two different types of limestone, one oolitic and one crystalline.

Figure 3. Depths of cut of the polymer-containing jet (left) and plain waterjet, operating at the same pump pressure, nozzle diameter and standoff distance (Glenn Howells)

Note that at the distance where the normal waterjet has broken into droplets (as seen by the nature of the cut surface) and the jet has barely enough energy to remove the surface layer, where the jet contains polymer it retains the ability to cut.

Further, and this is more critical where cut quality is more important, the jet cut is much straighter and cleaner than the dispersed and wider normal cut. This can be seen where a different, more crystalline limestone has been cut closer to the nozzle.

Figure 4. Change in the cut shape to a narrower, deeper cut where polymer is added to the jet stream (rhs)in cutting limestone. (after Glenn Howells)

The benefit of the improved performance changes therefore with the distance of the target from the nozzle, with the more dramatic improvement being seen as the target gets further from the nozzle. Looking at the data from the original work that we did in Leeds, back in the early days of this study, this can perhaps be better realized through the use of a 3-D plot.

Figure 5. Improvement in cutting performance as a function of distance from the nozzle and jet pressure.

Note that, in these trials, the polymer improved the jet performance relatively more at lower pressures and greater standoff distance. Part of the reason for this (in hindsight close to 50-years after running the tests) is that when the jet was cutting at the lower pressures it was closer to the threshold pressure of the rock and this any drop in jet pressure had a more significant impact on cut depth than occurred at the higher pressures, where the gain was not relative to such a low benchmark.

For a number of years, until our research took us into fields where use of the polymer was precluded for several reasons, we routinely used a polymer (generally Superwater, marketed by Berkeley Chemical) rather than Polyox because it gave a relatively consistent and significant improvement in performance plus, being a liquid, it was relatively simple and inexpensive to buy a small metering unit (about the size of a small case) which would feed the polymer into the water supply line to the pump at the required concentration – typically 0.1 to 0.3%.

It tends to work better in improving abrasive jet cutting when it is used with a Direct Injection of Abrasive (DIAjet) or Abrasive Slurry Jet (ASJ) system than with conventional abrasive waterjet (AWJ) systems. The reason for this is that the AWJ system has the abrasive fed into the water stream at the mixing chamber just before the jet leaves the nozzle to strike the target. Within the mixing chamber the abrasive has to penetrate into the waterjet stream in order to acquire the jet velocity, and to distribute across the jet and give an even cut on the target.

Where the abrasive is feeding in from one side of the jet and the waterjet stream is more coherent, it becomes more difficult for the abrasive to penetrate the stream, and if the design is not adjusted accordingly, the cutting performance can be diminished, particularly relative to the gain that can be achieved where the combination is carried out effectively.

On the other hand with the ASJ systems the abrasive is mixed with the water far upstream of the nozzle and the are already thoroughly mixed together, so that the added cohesion of the jet will help to provide the acceleration that the particles need to reach close to the waterjet velocity, and achieve the improved cutting performance required.

Where an ultrahigh pressure jet does not contain abrasive, the polymer can be of benefit as a means of improving cut quality – as evidenced from this comparison in cutting a shoe sole pattern, both with and without the Superwater polymer.

Figure 6. Shoe sole cut comparison with and without Superwater. Note the smoother cut, with less fraying of the back side of the cut with the polymer. (after Glenn Howells)

Waterjetting 32c - more tests with polymers

In the last post on this topic I pointed out that one of early drivers to the use of long-chain polymers in water came from the reduction in friction that it provided to fluid flow through long pipes. In many instances this has been the driving force for the selling of the product, and in industries such as oil well drilling and fracking the reduction in friction down long relatively small diameter drilling pipe has been a significant selling argument.

The cohesion of the jet, once it leaves the nozzle, is a secondary consideration in overall economics, yet in some applications, such as the cleaning of down-hole completion screens, the ability of a polymer-laden waterjet to penetrate through the pressurized fluid in an oil well to reach and clean the screen has been the main reason that the market developed.

Figure 1. Improved jet power underwater when polymer is added (after Zublin)

One of the first steps to be addressed was the practical considerations as to how we got the polymer into fluid that made up the jet stream. The original polymer that I used was polyethylene oxide (Polyox) which was marketed in the form of small prills of chemical. The problem that we were then faced with is that, when these are just dumped into a container full of water, that the outer edge of each prill soaked up some water, became gel-like and adhesive, and stuck to the next particle, in a way that made a large collective lump that was very difficult to dissolve into the surrounding water flow. Even when the particles were fed in slowly into a fluid mixer the particles initially tended to concentrate in one layer of liquid, which only slowly dispersed into the main body of the fluid. That concentrated polymer has a number of interesting properties.

Figure 2. Lifting a thick concentration of polymer from a bucket by hand.

For example it can be thick enough that one can grab it with one's fingers and lift it that way out of the bucket, as the picture above shows, or it can cause a unique problem in a mixing tank.

The polymer can wind up around the mixing paddle shaft and work its way up the shaft until it hits the retaining screw at the top. It then piles up at this point until it reaches a critical mass, when a tendril can be thrown out of the tank, through the centrifugal force exerted through rotation of the paddle shaft. The tendril falling outside the tank falls to the floor, which is lower than the fluid in the tank, and thus the concentrated layer of polymer is drawn up the inside of the tank, over the side and down the outside of the tank since it is still attached to the escaping tendril. The result clearly showed that liquid could flow uphill, when pulled by the cohesion inherent in the high concentration polymer.

This, in turn, gives either a disadvantage (if you are using this in a factory) or an advantage to the use of the polymer. The reason comes from the fluid nickname – Slippery Water.” The addition of the polymer, while reducing friction in the pipe, also reduces it between a person’s shoe and the floor, and thus it becomes a hazard in the workplace, since it increases the risk of slipping. It has the impressive title Anti Traction Mobility Denial System . We used to call it Banana water, but that seems to have faded from use.

The need to reach the very low concentrations of polymer that are all that is necessary to enhance jet cutting required a better way of mixing, The recommended answer was to briefly suspend the particles in a suspension of isopropyl alcohol (swirling it in a cup worked well) and then dumping it into the tank in a way that ensured that the individual prills were distributed away from one another. And while this worked, it was somewhat cumbersome and worked well only when mixing up individual batches of water – useful in a laboratory but not so much in a factory that must operate steadily for a full shift.

A number of different chemical liquid additives, most particularly polyacrylamides and derivatives of guar gum, have been tested, with the original work (carried out with the help of Dr Jack Zakin) being carried out in special section of the Baxter Springs plant where we could photograph jets at one-millionth of a second in order to study their structure. To do that we set the system up so that the jet was back-lit, so that we could determine how solid the core jet was, and used a high-speed strobe to illuminate the jet for the short-time needed to freeze the jet motion, leaving the camera shutter open for that time. This meant that the room was totally dark, and since the tests were carried out in the middle of summer, it made for an interesting couple of weeks.

Figure 3. Improved cohesion of a 30,000 psi jet when polymer is added (lower picture) the jet range shown in the picture is about 8 inches.

We also ran a pressure transducer across the different jets, at different standoff distances, so that, for the most promising additives, we could measure the differences in impact pressure and jet cohesion as the transducer moved away from the nozzle. The results were reported in the Proceedings of the 3rd ISJCT with the different chemicals tested ranked according to their ability to improve jet cohesion and reduce jet spread.

One of the problems with some of the additives is that they are temperature sensitive, and the jet was coming from the nozzle at temperatures between 95 and 115 deg Fahrenheit (it was a hot summer and the water reservoir was not chilled). This was not recognized at the time, and it did have some impact on the performance of some of the chemicals, which also showed a tendency to rapidly age once mixed, due to the storage conditions. Nevertheless the results showed that while Polyox was the best compound, there were liquid alternatives that also were effective, and the technology has since switched to liquid additives of which I will have more to say next time.

Zublin, C.W., "Water Jet Cleaning Speeds - Theoretical Determinations," 2nd U.S. Water Jet Conference, Rolla, MO, May, 1983, pp. 159 - 166.
Zakin, J.L., Summers, D.A., The Effect of Visco-Elastic Additives on Jet Structure," paper A4, 3rd International Symposium on Jet Cutting Technology, Chicago, IL, May, 1976, pp. A4-47 - A4-66.

Waterjetting 16b - Optimum Abrasive Feed Rate and Depth

The post that I wrote last week was focused on the misperception that you need to add more abrasive to an abrasive waterjet if you wish to cut through thicker material. This is wrong on a number of counts, but most particularly because a good operator will have tuned the nozzle to achieve the best cutting jet, based on pressure and abrasive feed rate (AFR) regardless of target material. What the operator may change is the operating pressure (which would change the optimum AFR) and the traverse speed since these control the depth and quality of the cut that the jet makes.

But, before leaving the topic, I would like to discuss, in a little more detail, the concept of the optimal amount of abrasive that one should use with a given jet, and what happens as that feed rate is changed. As I mentioned last time, because of differences in the shapes of the mixing chambers of the nozzles supplied by different manufacturers, the specific sizes and optimal flow rates will differ from nozzle to nozzle but the overall conclusions remain the same.

Last time I pointed out that the driving waterjet had to break up within the mixing chamber in order to properly mix with the abrasive and to bring this up to a maximum speed before the mix left the focusing tube. Where the driving jet is too large then this breakup is not complete and the mixing is not efficient. As a result the jet that comes out of the end is more diffuse and the abrasive will not have reached the full velocity possible. However, if the incoming waterjet is made smaller for the same AFR and other mixing chamber geometries, then the cutting performance will decline.

Figure 1. Effect of increase in jet pressure when cutting aluminum with an AFR of 1.7 lb/minute (after Hashish, M., "Abrasive Jets," Section 4, in Fluid Jet Technology- Fundamentals and Applications, Waterjet Technology Association, St. Louis, MO, 1991.)

For a similar reason adding a polymer to the jet fluid should only be carried out with some care for the consequences. Long-chain polymers can give a jet increased cohesion and this can, at high enough concentrations, inhibit jet breakup in the mixing chamber thus reducing the effectiveness of mixing in the chamber.

Figure 2. The effect of changing cutting fluid on AWJ performance (after Dr Hashish ibid)

Polyox, (polyethylene oxide) is an extremely effective polymer for increasing jet performance by cohering the jet and reducing the friction losses between the pump and the nozzle. However, as the graph shows, adding it to some abrasive systems will reduce performance since the more coherent jet makes it more difficult for the abrasive to mix and accelerate to full velocity. At lower concentrations the polymer allows the jet to breakup, but keeps the slugs of water together making energy transfer more efficient. Higher velocity abrasive means that less is required to achieve the same cutting performance as Walters and Saunders showed.

Figure 3. Effect of adding polymer in reducing the amount of abrasive required to cut stainless steel (after Walters, C.L., Saunders, D.H., "DIAJET Cutting for Nuclear Decommissioning," Paper J2, 10th International Symposium on Jet Cutting Technology, Amsterdam, Netherlands, October, 1990, pp. 427 - 440.)

At low levels of abrasive feed Dr Hashish has shown that increasing the amount of abrasive in the feed increases cutting performance.

Figure 4. Effect of increase in AFR on depth of cut in mild steel at a feed rate of 6 inches/min (After Dr. Hashish ibid), waterjet diameter 0.01 inches.

However, as the abrasive flow rate continues to increase the cutting performance reaches a plateau and can decline, as Dr. Hashish illustrated. An AFR of 20 gm/sec is equivalent to a feed of 2.6 lb/minute.

Figure 5. The effect of higher AFR on cutting depth at 3 jet pressures on a mild steel target (after Dr. Hashish ibid)

Note that in this case the nozzle geometry was not optimized for operation at the highest jet pressure. More visibly we ran a series of cuts across a granite sample, where the only thing that changed between cuts was that we increased the abrasive feed rate in cuts from the left to the right. It can be seen that beyond a certain AFR the jet starts to cut to a shallower depth.

Figure 6. Successive cuts made into a granite block at increasing AFR from the left to the right.

Interestingly the optimum feed rate doesn’t just depend on the pressure and water flow rate (waterjet orifice size) of the system. Faber and Oweinah have shown that as the feed particle size gets larger, so the optimum AFR reduces.

Figure 7. Optimal Abrasive feed rate as a function of particle size (after Faber, K., Oweinah, H., "Influence of Process Parameters on Blasting Performance with the Abrasive Jet," paper 25, 10th International Symposium on Jet Cutting Technology, Amsterdam, October, 1990, pp. 365 - 384.)

The process of finding an optimal feed rate for a system is thus controlled by the design of the mixing chamber based on the relative position of the abrasive feed tube and the size of the waterjet orifice. This controls how well the abrasive that is fed into the system can mix with the jet and acquire the velocity that it needs for most effective cutting. Then, as the above plot shows, the optimal AFR is also influenced by the size of the particles that are being fed into the system, since as the particles become larger beyond a certain size, so the cutting effectiveness declines.

Part of the reason for this is that, as the AFR increases so there is an increased risk of particle to particle impact breaking the particles down into smaller sizes. (And an earlier post showed that smaller particles cut less effectively – as does figure 7 above). We screened the particles that came from several different designs of AWJ nozzle assemblies capturing them after they left the nozzle but without further impact, so that the size range is indicative of that which a target material would see,

The table is a summary of some of the results and it shows results for a feed that began at 250 microns giving the percentage of the particles that survived at larger than 100 microns.

Figure 8. Percentage of the 250 micron sized feed that survives at above 100 micron for differing jet conditions. (the numbers are averaged from several tests).

It can be seen that when the feed rate rises to 1.5 lb a minute that there is a drop in abrasive size at higher jet pressures, and this is likely to be due to the increased interaction with particles. Since cutting effectiveness is controlled by particle size, count and velocity the only slightly greater amount of particles that survive above 100 microns at 1.5 lb/minute relative to those that survive at 1 lb/minute suggest that spending the money to increase the AFR above the optimal value (in this case around 1 lb/min) is a wasted investment.

It is therefore important to tune the system to ensure that, for each jet pressure and nozzle design that is used, that the AFR has been optimized.

Waterjetting 7a - An intro to jet structure

Once a waterjet starts to move out of the nozzle with any significant speed, as the pump pressure begins to build, it becomes more and more difficult to look at the stream of water and get any realistic idea of its structure. Mainly what is seen is the very fine mist that surrounds the main body of the jet, and while some idea of the structure can be obtained by making cuts through material, it can be quite expensive to actually see within that structure. Part of the problem is that though the mist is very fine, it is also moving at speeds in the range of a couple of thousand feet per second. The human eyeball isn’t quite that fast. But we can use a very high-speed flash (in this case it was on for two millionths of a second) which has the effect of “freezing” the motion.


Figure 1. 40,000 psi jet issuing from a 0.005 inch diameter orifice, front lit.

However this mist still hides the solid internal structure of the jet and does not change much in relative structure, even when the internal jet conditions can be quite different. Fundamentally the internal structure was described by Yanaida at the 1974 BHR Group Waterjet Conference, and his description has been validated by many studies since.


Figure 2. The break-up pattern of a waterjet (Yanaida K. “Flow Characteristics of Waterjets,” 2nd BHRA Conf. 1974, paper A2.)

This structure holds for jets across a wide range of pressure and flow volumes, but it is difficult to determine the exact transition points of that structure conventionally. And this can lead to very unfortunate results. I have twice seen people back a nozzle away and then move their hand in front of the jet to show that even high-pressure jets (these were being used to cut paper products and had no abrasive in them at the time) could be “safe.” If both cases the individuals were very lucky to escape injury (water can penetrate the pores of the skin and lacerate the internal parts without any surficial signs of injury, and, as I showed last time, if the nozzle is too close it will slice through flesh and bone). I thought to take today’s post to show, though the use of photographs, why that was such a stupid action.

The photos were taken down at Baxter Springs, KS in the early 1970’s and involved the use of what was then a MacCartney Manufacturing Co intensifier, to shoot jets of varying pressure, and nozzle diameter along a path, so that we could see how coherent the jets were. As I mentioned above, the problem with looking directly at the jet is that the internal structure is hidden by the surrounding mist. To overcome that part of the problem we shone the light along a ground glass screen (to diffuse it) that was placed behind the jet, so that we could see the outline of the internal structure.


Figure 3. Arrangement for taking photographs of a high-speed jet.

This more of the downstream mist from the photograph, and a much better idea of the internal structure of the jet, and where the solid section ended could be measured.


Figure 4. Backlit, 30,000 psi jet issuing from a 0.01 inch diameter nozzle, the distance across the photograph is 6 inches.

The benefit of the technique is perhaps more evident when nozzles at different pressures and diameters and different chemistry are compared. First consider the change with an increase in jet diameter. From the front-lit view there is little difference in the jets. From the backlit, it is clear that the smaller diameter jet only reaches 3-inches across the screen, while the larger jet barely reaches the end of the range.


Figure 5. The effect of doubling the orifice diameter at the same jet pressure on jet range, the photo length is 6 inches.

One of the parts of the study we were carrying out in 1974 was to examine the effect that adding different long-chain polymers had on jet structure. The ones that we were looking at include some that are now used in the oil and natural gas industry to make the “slick water” that is used in the fracking industry to improve production from shale reservoirs. But it also has an advantage in “binding” the jet together. And so, in the study, Dr. Jack Zakin and I tested a wide range of different polymers to see which would be give the best jet.

There were a number of different things we were looking for. In cutting paper, soft tissue and water sensitive material for example, the polymer can bind the water sufficiently well as to further lower wetting to the point where it doesn’t have an effect. It also can improve jet cutting under water – but I’ll cover those in a few post on polymer effects that will come to later in the series.

The effect of a polymer (in this case an AP273) is shown in two tests where the only change was to add the polymer to the water for the lower one.


Figure 6. Jets with an orifice diameter of 0.01 inches at a pressure of 20,000 psi, the range is 6 inches, and the lower jet has had the polymer AP273 added to the water.

The narrower stream in the lower frame is the effect that we were looking for. Putting change in diameter and the better polymers together gave, as an example, the following:


Figure 7. The effect of changing jet pressure, nozzle diameter and polymer content on jet cohesion.

It might be noted that the jet in the bottom frame has as much relative concentration (and power) at the end of the range as the top jet had at the beginning of the range.

Now it all depends on what you want the jet to do, as to which condition you wish to achieve. Inside abrasive mixing chambers the object is much different than it is when the object is to cut a foot or more of foam with high quality edges. And there have been some interesting developments with different polymers over the years, but I’ll save those stories for another day.

But bear in mind that those individuals who could slide their fingers under the jet in the top frame of figure 7 would have had them all cut off if the jet had been running instead under the conditions of the bottom two frames, and in all three cases, to the naked eye the jets looked the same.

OGPSS - Chemical floods to enhance oil recovery

Before returning to look at the larger oilfields in the United States, I thought to describe ways of increasing the oil produced from the stripper wells that I mentioned last time. It seems appropriate to tie this to the time that I am writing about Texas, since some 41% or so of marginal oil well production comes from that state. And I would acknowledge again the help of the Stripper Well Consortium.


In the main, as Rockman has pointed out, the economics of production severely limit the options for increasing the flow of oil from these strippers. However changes in market price, and the reduction in costs of some of these treatments can make enhanced oil recovery (EOR) techniques worthwhile. And, even if not presently economic, as research studies ways of lowering the cost, driven in part by the size of the market, and the need for oil, so the likely increase in the price of that oil will change the economics in a positive (for the well owner) direction. This post is therefore going to look at the use of chemicals to stimulate enhanced oil recovery with a particular thought for stripper wells.

As an example I am going to consider the Lawrence field on the Illinois side of the Illinois:Indiana border, since this is part of an ongoing project.

Location of the Lawrence oil field in Illinois (Rex Energy )

The field had, by 1950, peaked and was in decline. However by waterflooding the field at that time, generally recognized as secondary recovery, the water displaced the oil, while maintaining pressure in the reservoir as fluid left, thus increasing production. though that too then began to decline.

Production from the Lawrence field in Illinois (DOE )

Some time ago Stuart Staniford explained some of the problems with a water flood, in terms of ultimately recovering all the oil from a formation.. The post itself deals with what is going on in the Ghawar oil field in Saudi Arabia, but, to understand that, one has to understand a little of the physics of fractional flow in a multi-phase fluid. And so he provided that explanation, which I am now going to borrow:

if there is 10% water and 90% oil in a particular volume of rock (.........), then a well into that part of the rock would be receiving 10% water and 90% oil. Similarly, an area with 60% water and 40% oil might be producing at 60% water cut into a well into that area. However, this is not so: the difference is much more dramatic than that. The reason has to do with the physics of two phase flow in a permeable medium. If you want a mathematical treatment, try this, but let me try to illustrate the basic idea.

In a set of interconnected pores through which oil and water are being forced at pressure, the flow is too turbulent for large areas of the two fluids to separate out from one another. And yet, oil and water do not like to mix, and will tend to bead up in the presence of the other. If there is only a little water and a lot of oil, then the oil will form an interconnected network of fluid throughout the rock pores, whereas the water will tend to make small beads within the oil. Conversely, a little oil in a lot of water will result in a network of water throughout the rock, and small beads of oil within that network. Now, in either situation, the fluid that is interconnected can flow through the rock without making any change in the arrangement of beads and surfaces between oil and water. However, the fluid that is beaded up can only move by the beads physically moving around, and they are going to tend to get trapped by the rock pores.

So for this reason, in a mixture of almost all oil, the water cannot flow at all. Conversely, once there is almost all water, the oil cannot flow at all (which sets an upper limit on the amount of oil that can ever be recovered by a water flood). In between, there is a changeover in which the proportion of oil flowing to water flowing changes much more rapidly than the changeover of the actual mixing ratio. The curve that describes this is called the fractional flow curve.

For example, the tutorial I referenced earlier shows this picture for a typical fractional flow curve:

"Typical" fractional flow curve (from this tutorial). Fw is the fraction of the flow out of the well that is water, i.e. a value of 1 is sensibly 100%.

So the way to read this is that when we are below 20% on the X-axis (less than 20% water in the oil), there is zero (water flow shown Ed) on the y-axis (the water will not flow through the rock at all). As we get above 20% water saturation, the flow of water increases rapidly, until above 80% water, there is no flow of oil at all. In the linear region at the center of the curve, the slope is about 3.6. That is, each 1 percentage point increase in water saturation results in a 3.6 percentage point increase in water flow in the rock.

Now this is not absolutely true, in that the mechanical motion of the water through the rock will drag a small fraction of oil along with it. Thus, at flows above 80% there will still be a small amount of oil that comes out with the water.

The amount of water that comes out of the well, as a percentage of the total flow, is known as the “water cut.” (And the obverse, or oil percentage is referred to as the “oil cut".) In Illinois the wells in the Lawrence field are running at a water cut of 98%. In other words for every 100 barrels of fluid pumped out of a well, only 2 barrels will be oil, and that must be separated from the water. In Saudi Arabia one of the characteristics of production that initially caught Matt Simmons attention was that the oil had a water cut of around 30 – 35%. But I’ll leave that issue to another day – though in passing, if you haven’t read Stuart’s post in it’s entirety (and the debate between him and Euan Mearns on Saudi productivity) it is well worth taking the time to do so.

What I want to return to for today is the remaining oil in the field. To put it simplistically, under normal conditions that oil is attached to the particles of rock in the formation, and the water flowing past only marginally can dislodge it and carry it to the well (hence the low oil cut numbers). Now if the chemistry of the oil could be changed, so that, for example, it did not cling quite as strongly to the rock, and, at the same time the viscocity of the oil was reduced, so that it would flow more effectively, then perhaps the water could carry a higher percentage of the oil away, increasing not only the oil cut, but also the total amount of oil that could be economically recovered from the wells. (This might also require getting the oil into an emulsion with the water).

There are a number of different techniques and fluids that can be used to make this work. The idea is not new, and back in the ‘80’s the hot topic was “Micellar flooding”, although it, and its cousin ASP flooding, have not been that successful – in the United States.

Production from chemical flooding of oilwells in the USA. (Dr. Sara Thomas*)

The letters that make up ASP stand for alkaline, surfactant and polymer. Generally the chemicals are injected as a slug, or a series of slugs, into the water injection well (s) and then pass through the formation to the collection wells, being pushed through by subsequent injections of more water.

The first of these, the alkaline chemical (think caustic), is aimed to mix with the oil and lower its bond attachment (the interfacial tension) between the oil and the rock so that it can be removed more easily. By itself, however, it does not seem have that great a level of success in improving oil cut, but it sustains the flow of the oil for a longer period.

Alkaline - polymer flood of the David Field in Alberta (Dr. Sara Thomas*)

The S in ASP stands for surfactant, and this acts in much the same way as does the alkali in changing the adhesion of the oil, but acts more as a soap in helping to break the oil free. It has been shown to be more effective as a tool for improving recovery than the alkaline solution.

Effect of a surfactant flood on well performance and oil cut – Glenn Pool Field OK (Dr. Sara Thomas*)

The polymer can either be used to thin the oil, so that it is easier to move, or to thicken the water so that it adds a more effective drag to move the oil. The benefits of this can be seen from a trial at the Sanand Field in India. Note that it also provides a more sustained effect.

Effect of injecting a polymer slug to enhance oil recovery (Dr. Sara Thomas*)

While each of these individually provided some gain, the impetus at present is to combine them in consecutive slugs (hence the acronym) and the benefit can be seen from the sustained improvement in oil recovery. (As you will note from the dates, this is not a totally novel concept).

EOR from a field in Daqing, China after an ASP treatment (Dr. Sara Thomas*).

And here is a different example from Tanner, WY.

Change in oil cut and monthly oil production following an ASP flood in Tanner, WY (Oil Chem technologies ). The cost per incremental barrel including chemical and facilities was estimated at $4.49.

With this understanding of the background to the potential use of the ASP treatment, lab tests have shown that it might be possible with this technique to recover an additional 130 mbbl from the Lawrence field. (Until now it has produced a total of 400 mbbl). The potential, if the technology can be proven to work is quite significant.

Potential additional oil that can be recovered if Chemical EOR is successful (Dr. Sara Thomas*).

The big question, that I included in my second paragraph, and that Rockman, (our resident realist) reminds us of, is the need for this to be a significant cost benefit to the operator before it will be implemented. Technically chemical floods can increase the oil cut from 1 to 20% of the flow, but in the earlier tests the chemicals used cost more than the oil recovered. It is not a simple process, since it depends on the rock geology to ensure that the chemicals have the proper access to, and path from the oil in place. And the additional services to ensure this also cost. Lawrence was the site where Marathon tried using chemical EOR in the past and achieved the technical success of increasing the oil cut to 20% from 1%) but it was uneconomic. With the new program Rex Energy are reporting, in their first quarter report, that the program is successful so far.

We are seeing positive results from the Middagh ASP project area with increasing oil cuts and oil production. . . . . . . . . . . . .

As a result, we have the confidence to increase our capital budget for the ASP program by $3 million to fund the larger 58-acre ASP project in the Perkins-Smith area. Results from the Middagh ASP are being analyzed to maximize oil recovery in the Perkins-Smith Unit. ASP injection on the Perkins-Smith Unit is expected to begin during the fourth quarter this year following brine water injection, which we expect to commence shortly.

The program is an area of considerable interest for the Stripper Well Consortium to whom I am indebted for some of the information in this post.

I would close, however, with a slide from Dr. Thomas’s presentation:

The growth of oil produced by chemical EOR (ASP flooding etc) in China (Sara Thomas)

* The graphs identified as “Dr. Sara Thomas” were taken from the SPE Distinguished Lecturer Series 2005 – Dr. Sara Thomas “Chemical EOR – the Past, Does it have a Future?” (Abstract here )