Q&A: The Science of Sand

Posted on April 5, 2023
By David Sobernheim
Download Post
Back to News & Blogs
The Science Of Sand

Energera COO David Sobernheim explains the role sand plays in the fracturing process and how Sandtinel separators work to eliminate it from production streams.

Question: How and why did sand make its way into the fracturing process?

David: Sand is the predominant class of proppants used in hydraulic fracturing stimulation, which first began in the 1940’s. A second step-change in sand volumes (the first being tight gas fracturing in the 1970’s) came with the advent of advances in horizontal drilling and multi-stage fracturing beginning around 2002 and really starting to take off in 2005, through to the present day.

The shale revolution, or the “shale-gale,” as its sometimes termed, was when we started pumping millions of pounds of sand into horizontal wells to create “superhighways” of high conductivity production flow into the wellbore. Somewhat analogous to Eisenhower’s interstate road system build-out of the 1950’s, which vastly improved transport in the US. That's hydraulic fracturing, and an analogy for you. The magic behind unconventional extraction is you can take very low permeability rocks, traditionally non-economic, put away a lot of sand, and suddenly you have proved reserves (economic) from previously uneconomic resources in place.

The flip side of pumping these large volumes of sand into a horizontal wellbore is after-stimulation: when you clean-up and flow the well, you'll have sand flowing out of the wellbore. That can cause a lot of expensive problems with your flowlines and production equipment. The good news is that there are solutions available to help.

“Sand unlocks the rock to release the hydrocarbons, but it needs to be dealt with down the line. That’s where Sandtinel comes in.”

Question: What are the different types of sand and why is it so important to know what you’re working with?

David: For many years, operators didn’t use sand, but rather ceramic particles, factory produced proppants that acted like sand, but are higher strength. These were more expensive and led to higher costs. Today, most operating companies have moved to sand and generally view near-wellbore duning and large volumes as sufficient to overcome impacts of proppant crushing in ultra-low permeability rocks. The wholesale move to sand, with rare exception, has led to lower costs and higher early productivities in unconventional rocks.

What is important about using sand is getting the perforating strategy, stage size, volumes, schedule, and prop size right. Generally, to get the best flow capacity of the sand, you need a relatively uniform particle size. So, you want a certain micron range size of your sand. Most wells these days are stimulated with what's called hundred mesh sand, a range of 70 to 140 mesh size, which is what the American Petroleum Institute (API) uses. So, it's a range, but it's all around 150-micron grain size, roughly. And that's kind of the status quo or the best combination of permeability placement and flow capacity. In “higher” low permeability reservoirs, 40/70 mesh range is often used as a portion of the treatment.

Very fine sand or crushed particles are generally harder to separate when it comes back in the flow stream, whereas more coarser particles in 100 or 40/70 mesh generally are much easier to handle the separation process with. So, when we do our CFD modeling, knowing the typical size range of the sand that's coming back out of the well, as well as the density, which for quartz is 2.65 is pretty typical. We like to get samples from the well and run a laser diffractometer analysis to nail down the particulate size we’re dealing with.

If you were using a ceramic proppant, as we call it, a factory-made proppant, those can be heavier weight, like in deep offshore, high-pressure wells. Here operating companies might use sintered bauxite, which is 4.2 specific gravity, much heavier than sand. So, we do need to know the density and the size to do the modeling and make sure we size our equipment properly for what's going to come back out of the well.

Question: What makes sand challenging to work with?

David: A lot of the understanding of how much sand you're going to get back from a particular formation, a particular reservoir bench in a particular area, depends a lot on the hydraulic fracturing technique such as what concentrations you're pumping into the wellbore and the volumes. There's a lot more art than science behind sand flowback prediction currently, but we expect that to change with greater digital sand measurement technologies and data science.

So, it's an area we need to learn more about. Today an operating company can have one well making 200 pounds of sand an hour and another well nearby that's making 3 pounds an hour. So, we must be able to handle a range of capacities in terms of what might come back as our sand separation solution and be agile when working with operators and the diversity of their needs based on what the well is producing.

Question: How does sand impact wear and tear on equipment?

David: You're dealing with an abrasive sand-laden fluid in a high-pressure environment which can abrade valves, pipes, equipment, and cause potential for pressure releases and spills because of that abrasion effect. If you're putting sand into tanks that are designed for water, oil or natural gas and you get a bunch of sand in there, that's not a good thing. Sand degrades equipment over time and left uncontrolled you're going to be washing out choke manifolds and pressure equipment piping, sending sand into separators and equipment that's not designed for sand, filling it up and eventually causing blockage and stoppage. This can create a huge safety hazard for any person in the area. It can be dangerous and expensive if you don't remove the sand from your flow properly.

To protect your facilities, you need to have a robust sand separation solution that’s going to minimize erosion effects and potential safety events. It's an important category that's gotten more important as stimulation designs have become more aggressive with more and more sand and water pumped into these wells. Additionally, aggressive flowback of wells, which typically leads to better economics, produces more sand from the well.

Question: How does Sandtinel mitigate that impact?

David: Our VL-TEK™ Vapor Lock Technology is unique in this space, and it's a highly effective sand separation technology that doesn't require any filters or other moving parts. It creates a barrier of gas in the upper part of the hemisphere and a settling area in the lower hemisphere that allows for a long settling path for sand and water while the hydrocarbon and gas is handled in the upper part of the vessel. This unique hydrodynamic effect allows for a very effective separation of sand from the hydrocarbon and water stream coming out of the wellbore, minimizing any entrained gas or liquid hydrocarbon in the sand laden water.

Our vapor lock design also yields a minimal pressure drop across the sand separator. This low delta-P means that you are not holding back your well’s productive capability. Sand can be handled with 95% plus separation efficiency across a range of flowrates, from high to low, with no diminishment of performance, with our technology.

Question: What happens to the sand once it's separated?

David: The sand is separated into a gentle settling area in the lower hemisphere of our vessels which will capture up to 600 pounds of sand, on a 48” vessel, depending upon flow conditions, before requiring draining. When we drain the vessel, the bottom of the vessel is opened via a valve while we're still flowing through the top. Pressure is used to push the sand and water out of the bottom of the hemisphere into a sand handling tank or other sand storage device while still flowing the well in a safe and controlled manner with minimal fugitive emissions.

Question: How does Sandtinel reduce emissions during production?

David: When you're separating the sand out from the flow stream, it's going to accumulate in your separator and there comes a point where you do need to drain the sand out. With Sandtinel units, we have a gentle, long path settling area for the sand in the lower hemisphere below the vapor lock. This allows for the accumulation of sand and water in the lower hemisphere and you don't have the gas bubbles entrained in the water - just sand and some water that's being pushed out to a tank.

“With most separators on the market, you will get fugitive emissions when you’re draining; with Sandtinel technology, this is at an absolute minimum.”

Question: How are Sandtinel separators safer than other separators?

David: Taking the sand out of your flow stream is important for general pressure integrity and facility protection and not having problems with pressure or fluid releases. Sandtinel vapor lock separators safely and effectively handle particle separation over a broad operating curve determined by computational fluid dynamics (CFD) modeling.

The only time you need an operator at a Sandtinel vessel is when you're draining (dumping) the vessel. And that's generally just a 15 to 20 second process of opening a valve at the bottom and then closing it. That's the limit of the exposure that the operator must be in the high pressure during the dump cycle. Pressure areas are typically called the “red zone” and it is a best practice to try and keep people out of these pressurized regions wherever possible.

New technologies including the Sandtinel Dispatcher automated dumping system which will remotely operate those valves and take care of the dumping process for you. This means no operator is required during that process, reducing exposure to zero and mitigating any safety hazards of the red zone.

Question: What are some of the factors operators should consider when choosing a separator?

David: A lot of times operators may not know how much sand the well will produce. And so, one challenge is the size of flowback iron they should use. Do they need to have more than one Sandtinel out there? Parallel separators? A series of multiple separators? What size of flowback iron? 3”? 4”?

The configuration can vary quite a bit and obviously impacts cost, trucking, personnel, and other factors that affect your bottom line and budget. What’s important is that we take our time from the outset and get it right the first time, because if you get it wrong, it's going to cost more money to correct that error.

We typically will request a “pre-install” datasheet, with such items as expected pressures, flowrates, sand type, and other pertinent data with which a CFD operating curve is constructed. Additionally, a post-install CFD model is run to validate the configuration with exact well data and sand diffractometer analysis of the flowback particulate concentration and size range.

Question: What kind of operation would benefit the most from using Sandtinel?

David: Just about any hydraulically fractured unconventional well completed today will have sand in the flow stream. So, all unconventional basins where horizontal well drilling and multi-stage hydraulic fracturing is deployed can benefit from Sandtinel technology (Permian, Eagle Ford, Haynesville, Mid-Con, Bakken, Powder River, Marcellus/Utica, Montney, Duvernay). These reservoirs are very sand prone following the fracturing treatment. In addition, unconventional basins in Argentina and other areas of the world where operators are becoming more active such as in Australia, China, and the Middle East are starting to see the benefits from effective sand separation in the production stream.

Operators who demand the highest possible sand separation efficiency, simple operation, minimal fugitive emissions, minimal back pressure, low variable costs, small footprint, and a broad operating curve are typically the ones who benefit most from our vapor lock sand separation technology.

linkedin facebook pinterest youtube rss twitter instagram facebook-blank rss-blank linkedin-blank pinterest youtube twitter instagram