The proppant choice

Oil and gas are resources of great economic importance. The recent advent of horizontal drilling in the US (and the associated hydraulic fracturing), means that cheaper natural gas is changing the shape of the market, but much hinges on the hard round grains known as proppants, so called because they prop open the fractures in the rock formation.

Proppants are generally made up of either silica (when specifically for hydraulic fracturing it is known as frac) sand, resin-coated silica sand, or ceramic proppants made from sintered kaolin or bauxite.

Without these, the whole process would fall apart but all these proppants differ considerably on cost, processing capability, fracture conductivity, logistics, and effectiveness in the various downhole situations.



A Cooke Conductivity Cell used for API
standards that tests conductivity downhole
Carbo Cermaics, Society of Petroleum Engineers


The importance of conductivity

The most important facet to any oil or gas well is conductivity - the flow of oil and gas back through the pipeline to the surface.

Conductivity is determined by the width of the fracture multiplied by its permeability driven primarily by proppant selection. The proppant is packed into the pipe and into the fractures so that the oil and gas can flow back through the space between the individual proppant beads.

Conductivity differs both between wells and between shales. Each well has its own unique situation requiring petroleum engineers to use a measure of conductivity to decide which proppant is most appropriate.

“The quality [of the proppant] is driving the conductivity (...) you can always improve conductivity but the point is that it is going to cost you more money to do it - so what is really needed is a cost benefit analysis,” Terry Palisch, director of petroleum engineering at Carbo Ceramics, a leading producer of ceramic proppants, explained to IM.

“Whereas perhaps ten years ago they [engineers] might have used all ceramic proppants in a well, now they may use ceramics in just a part,” Bryan Shinn CEO of US Silica told IM, adding that cost efficiency is now the driving force.

All petroleum engineers now focus on maximising conductivity at minimum cost: “The real question that a person has to ask when selecting a proppant is how much conductivity do I need in this well,” said Palisch.

After the appropriate level of conductivity is decided, the proppant and fluid make-up is selected in order to provide the most economical well drilling solution.

Measuring conductivity

Conductivity is measured using American Petroleum Institute (API) and ISO standards which involve laboratory tests using a Cooke Conductivity Cell (see below) which determines the conductivity downhole. This will then be used to evaluate which proppant to use.

At the actual well site, engineers can also carry out a pressure transient analysis which is where measurements of well pressure are taken when the well is flowing and this helps show the length and conductivity of a fracture pattern.

However, “the problem is those conditions don’t necessarily mimic what is going on in the well and so the really critical piece of proppant selection is predicting the conductivity of the proppant with the specific well conditions,” Palisch explained to IM.

“Unfortunately, while the modified API test provides a good indicator of the performance of proppant under laminar conditions in the laboratory, it drastically overestimates the conductivity of the proppant when placed in a real hydraulic fracture,” Terry Palisch and Robert Duenckel of Carbo Ceramics pointed out in a 2007 paper.

“This is because reference values have not been corrected for effects such as non-Darcy or multiphase flow, gel damage, filter cake, fines plugging, cyclic stress loading, long term proppant degradation and many other phenomena which will increase the pressure losses within the fracture. None of these effects is accounted for in any standard conductivity test. Indeed, it is not uncommon to see as much as a 99% reduction in conductivity under realistic conditions,” they added.

This means determining realistic conductivity is extremely important and can affect the choice of proppants.

The perfect proppant

An ideal fracture would possess infinite conductivity without the need for proppant. In reality, a proppant is required that ideally would be uniformly placed over the created length and not be subject to conductivity damage.

Proppant characteristics, as per API specifications, are expressed in mesh size, roundness/sphericity, crush resistance, quartz content (SiO₂), bulk density, specific gravity, solubility in acid and turgidity.

These are all important because they are the factors that drive conductivity and indicate how effectively the proppant will perform in the well.

Mesh size

This is the size of the particle (or bead) of proppant. The most common mesh size used is API certified mesh sizes of 8/12, 10/20, 20/40, or 70/140 with 20/40 being the most widely used for frac sand.

The change in pressure of closure that proppants will stand has a lot to do with the mesh size. A very large particle will withstand very little closure. However, a very small particle (because there are several of these particles in the same area) improves the closure pressure as it is more efficiently distributed so 20/40 mesh proppant will withstand less closure than 40/70 proppant because there are significantly more contact points on the 40/70 per square foot of the fracture pattern.

Roundness/sphericity

The standards prepared by the API in this regard simply estimate how closely the quartz grain conforms to a spherical shape and its relative roundness.

The grain is classified as “average radius of the corners/radium of the maximum inscribed circle”.

Krumbein and Sloss devised a chart for the visual estimation of sphericity and roundness in 1955 as shown on the right. API recommends sphericity and roundness of 0.6 or larger.

The roundness dictates how the proppant will fit together in the fracture and a more round proppant will mean that there is more space for the oil and gas to flow back along the pipeline, improving the conductivity.

Crush resistance

API requires frac sand to be subjected to between 4000 psi and 6000 psi pressure for two minutes in a uniaxial compression cylinder to determine its crush resistance.

In addition, API specifies that the fine particulates from the crushing of proppant beads (fines) generated by the test should be limited to a maximum of 14% by weight for 20-40 mesh and 16-30 mesh sizes. Maximum fines for the 30-50 mesh size should be 10% or less. Other size fractions have a range of losses from 6% for the 70-40 mesh to 20% for the 6-12 mesh size, Mark Zdunczyk, consulting geologist, outlined in IM in January 2007.

Crushing, and the production of fines, is a function of grain brittleness, which correlates to grain shape, and the internal structure of the grain itself, as well as overgrowths on the grain.

The crush resistance is important for keeping the fracture open so the proppant does not cave in under pressure and allow the fissure to close and stop the flow of hydrocarbons.

With respect to hardness, normal silica sand might have a strength allowing it to withstand fracture closure stresses up to about 5000 psi. In normal oilfield operations, synthetic proppants are used where closure forces are expected to be above roughly 5000 - 8000 psi but there is no definite measure as it depends on well conditions.

Frac sand should also have a high quartz content (>99% SiO₂). A high SiO₂ content generally means that the proppant is likely to have a higher crush resistance.

Bulk density

Also know as porosity, bulk density is the mass of proppant per unit volume (eg gram/cubic centimetre). The volume of both the grains themselves and the voids between the grains are included.

Bulk density is useful to gain an estimation of the weight of a proppant needed to fill a fracture or a storage tank.

Specific gravity

This is also called apparent density and includes internal porosity of a particle as part of its volume dictating the speed at which a particle will settle when suspended in water or gel. It is ideal to have the specific gravity as close to the fluid as possible without compromising the hardness.

Solubility in acid

This test measures the loss in weight of a sample that has been added to a 100ml solution made up of 12 parts hydrochloric acid (HCI) and 3 parts hydrofluoric acid (HF) and subsequently heated at 150ûFahrenheit (approximately 65.5û centigrade) in a water bath for 30 minutes.

The object of this test is to determine the amount of non-quartz minerals present.

API specifications require that losses by weight as a result of this test are restricted to <2% across all mesh sizes up to 40-70 mesh where the loss permitted rises to 3%.

Turgidity

Turgidity refers to the amount of silt of clay sized particles in the sand sample. This is generally not an issue in frac sand production as it requires a washing process to be introduced which effectively removes these particles.

The best proppant is one that is extremely hard (crush resistant), extremely round (sphericity), of a similar density to water to prevent settling, and extremely cheap.

“Proppant selection in a perfect world with unlimited supply comes down to cost verses benefit,” Palisch told IM.

Frac sand

Silica sand, known more colloquially as frac sand when specifically used for hydraulic fracturing, is the cheapest and most readily available of proppants in the US. Frac sand was first mined from the brown Hickory (Brady) silica sand deposits in Texas, US, where large scale production continues, later from the white to off-white St Peter (Ottawa) sandstone formation in the mid-west states of Minnesota, Wisconsin and Illinois - both of which are Cambrian-Ordovician sandstone formations.

Older silica sand formations tend to have much older and rounder grains that are much better suited to hydraulic fracturing than younger deposits.

With sand, mesh size is critical and the vast majority of grains range from 12 to 140 mesh and include standard sizes such as 12/20, 16/30, 20/40, 30/50, and 40/70.

Generally, coarser proppant allows for higher flow capacity owing to the larger pore spaces between grains. However, it may break down or crush more readily under stress due to the relatively fewer grain-to-grain contact points to bear the stress often incurred in deep oil- and gas-bearing formations.

“Coarser proppants, such as 16/30 and 20/40, can be more difficult to effectively place in fractures due to their size and higher settling rates compared to, for example, 40/70 and 100 mesh,” explained Robin Beckwith of the Society of Petroleum Engineers.

The increasing use of 40/70 and finer 100 mesh sands beginning in 2001Ñrising particularly since 2006Ñ is a rather new development resulting from the rise in high-volume slickwater fracturing of unconventional horizontal gas wells such as those in the Barnett, Fayetteville, Haynesville, and Marcellus shales, he added.

“The trend in proppant sizing in unconventional gas wells had been toward smaller proppants in the hope that more of the proppant could be placed farther into the reservoir. With the shift back toward oily reservoirs, the need for higher proppant conductivity to move liquids at high rates has caused a shift back toward larger proppant sizes,” explained Kevin Fisher in a recent American Oil and Gas article.

The significant difference between frac sand and other proppants is cost. “When you look at the cost of our product, frac sand versus the ceramics, it’s about a ten-to-one difference. So it really makes a dramatic difference to the end-use customers in terms of their cost of the wells,” Bryan Shinn of US Silica explained to IM.

If frac sand has a good mesh size, it can still fail on its roundness. The rough and uneven granules fit together like a jigsaw puzzle and reduce conductivity and the roughness of the surface of the sand particles also hinders flow back along the pipeline.

As a proppant, silica sand struggles to function in deeper wells where it is subjected to much higher pressure (psi) and temperature.

Resin-coated sand

Resin-coated sand is silica sand that has been coated in a resin to improve it as a proppant and accounts for about 15% of market supply.

“The microscopic coating adds to the strength of the grain that is coated, the sand grain or the ceramic grain. Depending on the type of substrate that you are coating it can double the closure strength or the resistance to crush that material can withstand,” Mike Smith, vice president, FTS International, Proppants and Coatings Division told IM.

This improves that sand’s quality and means that in can be used in a well with much higher pressure at greater depth.

But resin-coated sand still relies on a supply of good quality silica sand: “If you are coating a substandard particle, because it is the majority of the material, then the pressure that material will be at in the fracture is the dominant factor in how much strength that material will have. So you have to be coating a relatively high quality sand,” said Smith.

The raw sand grain needs to be virtually 100% silica; it needs to have high quality roundness and sphericity as well as very low solubility and it needs to be monocrystalline in nature because naturally fractured sand grains do not stand much closure, Smith outlined.

The resin has another advantage as well in the elasticity provided by the coating that helps to bond the particles together. When the proppant is placed in the well the resin between the particles binds creating a wider footprint meaning the pressure that the grain sees is now distributed over a slightly larger area so it can withstand more pressure.

The resin will also help to hold the proppant in place if there isn’t sufficient closure to do so.

Additionally, resin-coated sand helps to prevent fines clogging up the proppant pack in the well and lowering conductivity, “when that sand [resin-coated] breaks, and it’s still going to break even if you put the resin on it, the resin will hold all the fines together so the shards don’t flow through the proppant pack and plug things up,” Palisch told IM.

Resin coating also helps to improve the surface roughness of the sand particles which improves the flow of gas back up to the surface.

“Resin-coated sands’ application range tends to be from zero up to about 14,000 psi,” said Smith.

In comparison to raw frac sand, resin-coated sand is more expensive because of the extra processing but it provides a smoother, harder proppant that provides better conductivity in higher pressure and temperature situations and the proppant in the well provides better conductivity than raw frac sand.

It does however retain some of the faults of raw frac sand, particularly in sphericity because of its angular shape.

Ceramic proppants

Ceramic proppants are the most expensive of the three main types of proppants and are manmade from aluminous-related materials, either the aluminous clay kaolin or the alumina feedstock bauxite.

Ceramic proppants have a great advantage over frac and resin-coated sand because they have no angularity. Ceramic proppants are also much more crush and thermal resistant so can survive in hotter deeper wells like those of the Haynesville shale.

“Ceramic proppants are significantly superior to sand as proppants for high temperature, high closure applications, and resistance to saline dissolution (É) they have better properties than most if not all sands,” said Pickard Trepess, marketing manager for Mineracao Curimbaba Sintered Bauxite proppants explained in April this year.

As a proppant, ceramic is by far the most effective source, providing excellent crush resistance, and great roundness because they are manmade.

It is much “stronger because it is an alumina-based product and (...) a good ceramic proppant should have a tighter sieve distribution which just means that it is more uniform in size and is also going to be rounder,” explained Palisch.

Ceramics have always had strong presence in the proppant market: “In the early days, back a decade or more, engineers were very conservative and didn’t need the extra performance of a ceramic but would specify it anyway,” Shinn of US Silica told IM. This was done because ceramics give the best conductivity for any well but have faded in recent years because the cost of a ceramic proppant can make a well uneconomical unless the well’s individual requirements necessitate it.

“In the environment that we have today with relatively low natural gas prices, what we see are ceramic wells - that by definition are the high cost wells - get turned off first. They are the first ones to get turned off but the first ones to be turned back on again,” said Shinn.

A well that uses ceramic proppant will be reactivated when natural gas prices rise because they are typically the more efficient wells with the best conductivity.

For wells with extremely high pressure, the ceramic proppants are coated in a resin giving them the same extra benefits as resin-coated sand.

Competition between proppants

Although frac sand and ceramic proppants seem to be competitors, there is in fact very little opportunity for substitution in the individual wells. As the three main types of proppants are used in very different situations and cost vastly different amounts, there is little direct competition.

“The wars get fought at the boundaries so if there was some displacement it would, for example, be a high-end resin-coated sand versus a low-end ceramic proppant,” Shinn explained to IM. Despite this slight displacement, the market shares will remain consistent: “We don’t see any dramatic share shifts in the market and we are not projecting that in the future,” he added.

A recent influx of low-cost low-quality ceramic proppant from China has caused some displacement but without sustained supply and consistent quality, the trend is waning.

So in the oil field drilling market, both proppants have their own niche and both will continue to be used by petroleum engineers for horizontal drilling.

There can be competition within the proppants themselves. Different types of sand, for example, compete quite strongly with some drilling companies using Brady brown sand and some using Ottawa white sand.

However, the majority of the proppants market uses frac sand, followed by resin-coated sand and ceramic with potential for expansion in all.

Substitution of resin for ceramic

Recently, Mei Yang with Cadre Proppants published a paper pointing out that resin-coated sand could perform as well as ceramics in deeper wells.

“For tight gas reservoirs, we correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. By keeping stimulation costs down, natural sand proppants have a much larger range of applicability than previously thought,” said Yang.

Matt Zinn of FTS International agrees, telling IM: “With long-term production results they [drillers in the Haynesville Shale] were seeing zero performance increase in the long term from the wells using ceramic versus our resin-coated proppants.”

“The Haynesville would be the highest pressure and temperature which would be the situation most conducive, in theory, to having issues with resin-coated proppants but there weren’t any production increases from the more expensive ceramic,” he added.

Proppant prospects in the pipeline

The Middle East and India are showing signs of potential new demand for proppants as unconventional oil and gas resources attract attention

Mike O’Driscoll

The Middle East is about to embark on a new phase of oil and gas exploration and development as existing reserves become exhausted and domestic demand for energy, especially in Saudi Arabia, increases.

The move marks a potential new era of demand for oilfield minerals used in drilling fluids including bariteÊ(barytes), bentonite, calcium carbonate, calcium chloride, and haematite, as well as for proppants used in hydraulic fracturing, such as frac sand and sintered bauxite and kaolin.

Trends in oilfield mineral demand in the Middle East is the focus for the next IM Roundtable, Oilfield Minerals Outlook: Middle East, 21-23 January 2013, Dubai (see p12-13).

Fracking from the Middle East to Asia

The evolution of hydraulic fracturing in the Middle East and its influence on proppants is the subject of the presentation by Pickard Trepess, regional sales manager Europe, Africa and the Middle East for Sintex International, part of the Mineracao Curimbaba group of Brazil.

Fracturing has been evident in the Middle East and the central Asian region for a long time. According to Trepess most operations have been performed using acid, where the formation is carbonate or dolomite, but there are many reservoirs that respond better to propped fracturing.

In his presentation, Trepess will summarise the experience from Algeria to north-east India, and the development over time, the local constraints, and the reasons for fracturing.

Trepess observes that many countries are now looking very seriously at shale gas exploitation as economies move away from oil, which can instead be exported onto the world market.

Countries that are active in propped fracturing include Algeria, Tunisia, Egypt, Oman, Saudi Arabia, India, and Kuwait.

Significant plans to increase activity in India, Oman, Saudi Arabia, and Algeria are underway. In the future it is expected that Iraq and Pakistan will be performing large operations, and that there will be enhanced activity in Kuwait and in other parts of the western regions such as in Jordan, Cyprus and Turkey.

Certainly these comments echo the sentiments widely expressed among oilfield service companies and oil and gas explorers at the huge Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC) held during 11-14 November 2012.

“Halliburton is focused on positioning ourselves for the unconventional and HP/HT [high pressure/high temperature] business of the future,” said Mike Hugentobler, Halliburton VP Middle East and Eurasia.

Hugentobler acknowledged that gas will be a “major focus” over the next few years in the Middle East. Key Halliburton goals include unconventional gas reservoirs, deep HP/HT well types, and remediation of mature fields.

Dr Bernard Duroc-Danner, CEO of Weatherford, said: “We need to look harder at unconventionals. There is a lot of experience coming out of the US oil patch. We will know a lot more in ten years on how to exploit these unconventionals, the frontiers, and the difficult shale areas.”

Saudi energy demand, especially from the domestic sector (with air conditioning a top user) is growing on average 8-10% pa. By 2030, domestic consumption will reach 6.5m bpd, thus exceeding exports, which are expected to decline as a result.

At ADIPEC, Khalid al-Falih, CEO of world leading oil and gas producer, Saudi Aramco, called for increasing conventional and unconventional gas supplies by almost 250% over the next 20 years. Aramco is to invest $35bn in oil and gas exploration and development over the next five years.

The Saudi company is also taking a leaf out of the US shale gas book. Aramco’s chief exploration manager at its new unconventional gas division, Saleh M Saleh, revealed that up to 50 Aramco staff are being trained in the US by the likes of Baker Hughes and Schlumberger in order to gain experience found in the US shale gas plays to utilise in Saudi Arabia.

Saleh recognises that the key to successfully developing unconventional gas plays lies within the oilfield service sector that has developed and implemented new technologies on a large scale in the US.

Proppant evolution in India

Hallmark Minerals (I) Pvt Ltd of India has been pioneering the manufacture of ceramic proppants in the country. AK Dasgupta, managing director, of Hallmark Minerals, will be presenting: “The future of ceramic proppants production in India” in Dubai.

Dasgupta maintains that ceramic proppant demand in India is expected to increase “many times” in the near future owing to modification of state policy to enhance oil exploration as well as liberalisation for private and global producers for shale gas based on unconventional drilling policy.

On 6 December 2012, US independent explorer ConocoPhillips announced that it was nearing a deal with India’s state owned Oil and Natural Gas Corporation (ONGC) to explore and develop shale-gas resources in the country.

ONGC plans to explore the Damodar, Cambay, Krishna Godavari, and Cauvery basins for shale gas.

The US Energy Information Administration (EIA) estimates that India has a total of 64 trillion cubic feet of potential recoverable resources, and has the 15^th largest technically recoverable shale-gas resources.

A recent report in Petroleum Economist recorded the conclusions of a study by analysts at Bernstein Research which cast some doubt on near term fruition of Indian shale gas development. India’s delayed shale-gas policy is expected to be released in April next year.

That said, it is reported that there remains considerable interest in tapping the nation’s shale gas deposits with horizontal drilling and hydraulic fracture stimulation techniques, thus indicating good prospects for proppant suppliers.

Key trends and developments in oilfield mineral supply and demand for the Middle East will be examined and discussed at Oilfield Minerals Outlook: Middle East, 21-23 January 2013, Dubai - see. p12-13 and www.indmin.com/oilfieldmineralsme.