Surprisingly, there are still operators trying to decide whether they should recycle. The question is why, and to that question, there is no real simple answer. From shale play to shale play, the motivation to recycle is different. Expensive disposal is the primary driver in the Marcellus, but also regulatorily driven as a source-reduction strategy must be developed by each operator to include procedures to maximize reuse of flowback and produced water.

spwm patton table3I’m sure there would have been pushback on this requirement if it wasn’t already less expensive to reuse produced water. Induced seismicity is increasing disposal prices in Ohio and Oklahoma, moving the needle toward produced-water reuse. In the Permian, it’s been water availability.

There are other drivers. Some people believe they need clay stabilizer in their frac fluid, and produced water is a suitable alternative. Others believe produced water can be friendlier to their formation and improve well production. Then there is the environmental stewardship argument—it’s just the right thing to do.

I’ll keep it simple. You can reuse produced water as a frac fluid cheaper than disposal. For those of you reading this and thinking I’m crazy, let’s talk a little about how much treatment do I need for reuse. In the table, there are produced-water reuse standards for five different operators for slickwater fracs. 


You can reuse produced water as a frac fluid cheaper than disposal.

So, let’s talk about frac method for a second. This table represents different standards for slickwater. These standards do not apply to crosslink gels, linear gels or hybrid fracs. Gels have a higher sensitivity to chlorides, and your chloride limits drop to the 30,000 to 40,000 range. Boron in your produced water can cause premature crosslinking. This makes boron another limiting factor for reuse with gel fracs.

The good news is slickwater is becoming the predominant method, and slickwater is far less sensitive to chlorides. The trend toward slickwater has lowered the bar for reuse standards, making reuse far less expensive. If you review the table, you could in some areas never exceed chloride limits even with 100-percent produced water.


SALT REMOVAL AND SCALE INHIBITION

If you look at the high chloride reuse goals in the table, you can see that salt removal is not required. This simplifies the treatment model for reuse. Along with salt removal is the general idea of softening or removal or reduction of total dissolved solids (TDS). Part of the justification of removing TDS is to lower scaling potential. The problem is most operators are going to add scale inhibitor to their frac fluid because of concerns that formation water will cause scale. If you’re going to add scale inhibitor regardless of the amount of softening you do, you devalue the need for softening, or TDS reduction or removal.


BLEND, BABY, BLEND

The logistics of aggregating all your produced water and having it available when you need it is challenging. Because of this challenge, brackish/ fresh water is used as a primary source water because you can plan on availability in any given area and ultimately use the produced water to supplement your brackish or freshwater program. This forces you to use blends.

A few years ago, we saw 20- to 30-percent blends, but today we are seeing 40- to 60-percent blends. Obviously, people are developing infrastructure, storage and getting better at aggregating produced water. Nonetheless, they need to blend to supply a reliable source of water. And with blending, comes dilution and with dilution, comes a reduction in scaling species. Combine this with the reality that produced water commonly has residual scale inhibitor in it, and you have a fluid where TDS removal is no longer required. The combination of dilution and residualscale inhibitor in the produced water results in a fluid that doesn’t exhibit any scaling tendencies.

Of course, this is a very general statement. You should perform some basic tests to confirm this and not just rely on predictive models. I’ve seen water that a predictive model showed will scale and then run a tube block test and see no scaling. The Dynamic Tube Block Test (DTBT) is typically used to verify efficacy of scale inhibitors. You use the DTBT and increase the scale inhibitor dose until you see no pressure increase over time and determine the appropriate dose for that scale inhibitor in that fluid. You can use the DTBT to evaluate scaling in general. And as we previously mentioned, there is residual scale inhibitor in produced water that is difficult to account for in a predictive model, making the DTBT a better indicator of scaling.

Where is all this heading? Salt removal or softening are rarely required for reuse of produced water. This trend has greatly reduced the cost of reuse treatment. Produced-water reuse has become a simple formula of bacteria, iron and sulfide control.


WHAT ABOUT OIL AND SOLIDS CONTROL?

Let’s follow the produced-water cycle. First, at the wellhead you have oil and solids separation. Then, you send your produced water to a centralized tank battery where you settle solids and separate oil and then on to a gathering system and off to a saltwater disposal well (SWD) where you generally will find a gun barrel-type of oil/water separator and some type of desander or centrifugal separator for solids control.

If these systems are optimized, the need for additional oil and/or solids control are rarely needed. That being said, we still see some additional oil and solids control systems, primarily to manage upsets. It is not unusual to have gun barrel effluent with less than 30 ppm oil. Again, reviewing our handy table, we see that result would meet most standards and is below the level that would result in an oil sheen. Solids are a bit of a different story.

The table shows in some cases a very aggressive standard. There are plenty of papers that discuss the formation damage caused by suspended solids, but over the years, we have seen solids control becoming more and more relaxed. If you have ever tried to achieve 5-micron filtration at 80 to 100 bpm, you understand what I’m talking about. You need a full-time crew changing filter bags, and you are probably rupturing bags before you ever get to change them, and before too long, you’re bypassing your filtration.

Then there’s the challenge of keeping an inventory of 5-micron bags. In the Marcellus, fear of naturally occurring radioactive material (NORM) has almost eliminated the practice of solids control. The practical limitation of consistently managing 5 microns has resulted in operators defaulting to 25 microns and sometimes larger. Add proppant fines into the equation, and then you must ask yourself, do I really want to pay to achieve a low micron TSS via filtration only to reintroduce TSS in the form of proppant fines? Proppant fines do behave a bit different than other forms of TSS, but that’s a story for another time.

Over the last couple years, we’ve seen less filtration and more settling of solids. We see pit systems with a primary and secondary pit, where the primary is used for settling and the secondary feeds their reuse program. Not everybody likes the idea of solids in their pits, but with dust in West Texas settling out in pits, it’s inevitable. There are some operators who gamble with using produced water from centralized tank batteries. In those cases, it is more important to include some secondary oil and solids control.

To achieve a low-cost produced-water reuse, optimize the existing systems to provide oil and solids control, use blends to control scale and an oxidizer for bacteria, iron and sulfide control with aeration in your pits to maintain water quality. This approach makes produced-water reuse very economical.

Earlier, I made the bold statement that reuse is cheaper than disposal, and I will explain what I mean. If both my SWD or my reuse are tied into the same surface equipment in the form of some solids control with gun barrels for oil separation, the difference is drilling a disposal well versus a produced-water pit, oxidation system and aeration system. So, if we look at a 20,000 BPD base case, I can build a pit, with an oxidation system and aeration for less than drilling a disposal well. I can reasonably guarantee capacity of the produced-water reuse system, but can’t with the disposal well. We will discuss the reuse versus disposal further in a case study in this issue.

Produced-water reuse has become inexpensive because of changes in reuse standards and better, more compatible completion fluids. But the bigger question is if you’re not recycling, what’s stopping you?

 

In the Marcellus, fear of naturally occurring radioactive material (NORM) has almost eliminated the practice of solids control.

 

 

Authored by Mark Pattonspwm markpatton

Mark Patton is president of Hydrozonix. He has more than 25 years’ experience in the development, design, implementation and operation of treatment technologies. Mr. Patton’s oil and gas background includes treatment systems for waters, wastewaters, drilling muds, tank bottoms and process residuals. He holds one produced-water patent with two additional patents pending.

Mr. Patton earned his B.S. in chemical engineering from the University of Southern California in 1985.