While the oil and natural gas industry has had its ups and downs, many speculate it is again poised for growth due to the current political climate. Subsequently, there is a renewed interest around proppants &#; the hard microspheres injected into well bores to &#;prop open&#; rock fissures allowing natural gas and oil to flow out. According to the Fredonia Group, North American proppant demand looks set to grow at an annual rate of 7.6% through .
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Frac sand, or silica sand, a naturally made, abundant quartz sand, is the most commonly used proppant due to its low cost and high availability. However, while frac sand offers an economic solution in most cases, some settings require a bit more ingenuity on behalf of the proppant.
Ceramic proppants &#; a man-made proppant, offer a tailored solution in more demanding drilling settings.
Benefits of Ceramic Proppants
While ceramic proppants cost more than their naturally-made counterparts, they do offer advantages that make them the preferred choice in some settings, because they are capable of maximizing the yield from a given well. These advantages include:
As well bores get deeper, the pressure on proppants gets higher, and frac sand is not always up to the task.
Ceramic proppants can withstand a much greater crush strength than traditional frac sand products &#; up to 10,000 psi.¹ This allows drillers to access much deeper shale formations.
Ceramic proppants also boast a number of characteristics that translate to better conductivity, or the effectiveness at which the petroleum product can flow around the proppants in the rock fissure.
Improved uniformity in size, shape, and overall sphericity allows natural gas or oil to more easily flow around ceramic proppants in the well bore.
Conductivity is further improved due to the stable thermal and chemical nature of ceramic proppants; there is much less risk for the proppant to thermally or chemically react with the shale formation causing an undesirable deposit to form, which would ultimately clog the fissure.¹
Because they are manmade, the characteristics of ceramic proppants can be much more tightly controlled than with sand products. Proppants can be selected based on a variety of engineered characteristics to offer a more tailored solution to the specific needs of a well site.
Within the category of ceramic proppants, proppants are also available in three sub-categories, with higher density proppants able to withstand greater stress:
Ceramic Proppant Production
Ceramic proppants can be made from a variety of materials. While most are made from bauxite, kaolin (aka China Clay), or a blend of the two materials, a variety of other materials may be used, including magnesium silicate and fly ash. Various additives may also be included.
The manufacturing process of ceramic proppants can differ, but in general, proppants follow the process described below.
Raw materials are crushed into powder form. Materials and additives may be mixed in to develop specialized formulations in order to maximize performance of the end product.
The powdered raw material is then pelletized to create a uniform, round pellet/granule product. Proppant sizing is a critical factor in the performance of a proppant at a given well and as such, producers often provide a wide offering of mesh sizes. Proppants are typically between 8 and 140 mesh and it is not uncommon to use multiple sizes at a given well.¹
Once agglomerated, pellets are dried to reduce the moisture content of the material. This is typically carried out in a rotary dryer or other type of industrial drying system. Pellets are classified via screening.
Perhaps the most important step in the process, on-size pellets are sintered in a rotary kiln to &#;cure&#; the pellets. This high temperature sintering, which occurs at around &#; º F, causes chemical and crystalline changes in the material, causing it to harden further, ultimately imparting the crush strength that will be required for high pressure drilling applications.
The hot material exits the kiln and is fed to a rotary cooler. The cooler cools the hot product so it can move on to storage or transport.
Ceramic Proppant Development
When working with ceramic proppants, feasibility testing and process development are often an integral part of developing specialized proppants. Source materials are often tested first at batch scale to confirm feasibility, then at continuous pilot scale in rotary kilns designed to simulate production conditions, depending on the capabilities of the testing facility.
Testing not only confirms feasibility of the intended process with the unique source material, but it also provides the data necessary, such as time and temperature profiles, for process scale-up and the design of a commercial scale unit.
Conclusion
While ceramic proppants make up a small portion of the overall proppant market compared to frac sand, they are still a valuable tool in high stress settings. Their thermal and chemical stability, combined with a more uniform shape and size, and their high conductivity, make them a worthwhile alternative for more specialized applications.
FEECO provides feasibility testing and process development around the manufacture of ceramic proppants. In addition to our testing services, we engineer and manufacture custom rotary kilns to meet your proppant sintering needs, as well as rotary dryers and coolers for the proppant production process. For more information, contact us today!
1.F. Liang et al. A Comprehensive Review on Proppant Technologies. Petroleum 2 () 26 &#; 39. Web. Feb. .
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 &#;s. A second step-change in sand volumes (the first being tight gas fracturing in the &#;s) came with the advent of advances in horizontal drilling and multi-stage fracturing beginning around and really starting to take off in , 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 &#;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.
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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.
Contact us to discuss your requirements of import oil plus proppant supplier. Our experienced sales team can help you identify the options that best suit your needs.