Technical: Fracking What Makes it Tick? – Demystifying the Why’s, Technology and Science behind Unconventional Oil and Shale Gas Extraction
This discussion is a first order review of the principles governing hydraulic fracturing of shale formations that give rise to natural gas. We will begin with a brief review of the qualitative aspects of unconventional recovery methods and then build, piece-by-piece a semi-quantitative framework for the design of a hydrofracturing treatment.
To do this we will discuss the engineering models used to design a hydraulic fracture treatment, and provide an introductory look at the theories, design methods and materials used in a hydraulic fracture treatment.
The objective is to improve your technical understanding of the technology and science behind unconventional recovery and hydraulic-fracturing. Success depends on imparting a better appreciation for the complexity and sophistication of the process.
It is hoped that this presentation piques you interest to conduct further research into this topic.
Click on images to enlarge!
Table of Contents
2: What Is Unconventional Oil and Gas
3: IOR and EOR Recovery
4: Enhanced Oil Recovery
5: Gas Recovery by Hydrofracturing
6: Permeability and Porosity
7: Fracture Mechanics
8: Fracture Formation Model
9: Fracture Design Guidelines and Calculations
10: Limited-Entry Treatment Procedure
11: Primary Considerations
13: Effective Conductivities and Damage Mechanisms
14: Fracture Fluid Design
15: Proppant Selection
17: Closing Comments
Contrary to what some may believe, hydro-fracturing is not the midnight shadows of witches dancing around a fiery cauldron brewing a magical potion of strange and spell binding ingredients to be forced into the bowels of earth to cause death and destruction throughout the world
Hydraulic fracturing is, however, a highly technical process to create or restore small fractures in an underground rock formation by pumping a scientifically derived mixture of fluids and materials at an injection rate that is too high for the formation to accept. As the resistance to flow in the formation increases, the pressure in the wellbore increases to a value that exceeds the breakdown pressure of the formation. Once the formation “breaks-down,” a crack or fracture is formed, the injected fluid begins moving into the fracture then out of the well to allow the entrapped gas to flow out of the borehole.
Hydraulic fracturing is used to extend the life of wells in mature oil and gas fields. It also allows for the recovery of oil and natural gas from formations that geologists once believed were impossible to produce, such as tight sand and shale formations.
Historically, fracturing can be traced to the 1860s, when liquid, and later, solidified, nitroglycerin was used to stimulate shallow, hard rock oil wells in Pennsylvania, New York, Kentucky, and West Virginia.
Yet, the methods used to recover oil and gas resources from reserves that do not give up their oil or gas easily, have always had a “black box” image. This is partly due to the knowledge about these methods, which occur thousands of feet below the surface are generally controlled by specialists and engineers out of the reach of the public domain.
To fill in this in this information gap, this conference focuses on the advanced technologies used to recovery oil and gas from unconventional rock formations.
What is Unconventional Oil and Gas
So what is unconventional Oil and Gas? Simply stated, unconventional oil and gas resources are more difficult and less economical to produce, than conventional oil and gas deposits, which are easier to produce in terms of the cost and method of producing it. Unconventional reserves are more costly because the extraction technology has not been fully developed or adds incremental cost.
A way to illustrate the differences between conventional and unconventional hydrocarbons employs a resource triangle, Figure 1
The triangle illustrates the relationship between the technical difficulty of extraction, the vertical axis, and the estimated recoverable volume, the horizontal axis. It is a graphical illustration of reserve properties to reservoir volume. It shows:
• Conventional resources at the apex have small volumes that are easy to develop. These basins are relatively inexpensive to get at, but hard to find,
• Unconventional oil and gas deposits near the base have large volumes that are difficult to develop, and therefore, more expensive to produce, but easier to find, for instance, shale formations, comprise the majority of the earth’s rock.
Unconventional resources include heavy oil, coal bed methane, tight gas sands, shale oil and gas reserves, and gas hydrates.
Early exploration and production focused on hydrocarbons deposits at the top of the triangle. Today, Industry pursues opportunities lower in the triangle when the resources at the top are inadequate to meet demand, and consumers are prepared to pay more to make unconventional gas development an economically sound investment. The increased supplies from Unconventional oil or gas production, may in fact, result in a drop in the retail price as demand falls short of the growing stockpiles.
Other criteria that differentiate unconventional from conventional reserves include permeability, porosity reservoir pressure, and gas or oil saturation. Porosity and permeability will be discussed in more detail later in this presentation. Conventional formations, such as sandstones and carbonates, are essentially a high- to medium-permeability reservoir that will produce economic volumes of oil and gas without large stimulation treatments or any special recovery process, small porosity illustration on the top right.
Unconventional formations, the lower figure on the right, such as shale that give rise to unconventional production methods are porous but less permeable than conventional reserves, small porosity illustration bottom right. This makes the shale relatively resistant to the release of the entrapped hydrocarbon
The lack of permeability means that the oil and gas typically remain in the source rock unless natural or artificial forces, such as facture stimulation, cause the rock to fracture and thereby allow the hydrocarbon to permeate out of the rock.
Improved and Enhanced Oil and Gas Recovery
During the life of a producing oil field, several production stages are encountered. In many cases, operators employ three stages of recovery – primary, secondary and tertiary, Figure 2. While, the primary recovery stage uses conventional extraction methods; the secondary and tertiary stages utilize unconventional techniques consisting of improved and enhanced recovery methods, called IOR and EOR, respectively.
Initially, when a field is brought into production, oil flows naturally to the surface due to existing reservoir pressure. During this primary phase, the natural pressure inside the reservoir forces the hydrocarbon to the surface. However, only about 10-20% of the Original Oil In-Place (OOIP), is produced at this stage. It ends; when the production rates are too-low to-be economical or the amount of gas or water in the output is too high.
As reservoir pressure drops, a secondary recovery phase may be employed to increase production from the failing wells. This stage involves the injection of an external fluid such as water or gas into the reservoir to force the hydrocarbons to the surface. This secondary recovery stage can increase total production to 20-40% of the OOIP. This stage, employing improved recovery methods, ends when too much of the injected fluid is returned at the well head.
Oil that is left behind after an IOR treatment is there because:
• either it has not been in direct contact with the injected fluid, or
• because of the capillary forces that exist between oil, water and the porous rock, retain it., as in the case of shale formations.
Lastly, the remaining oil can be recovered by a variety of enhanced unconventional recovery methods; such as hydrofracturing, CO2 injection, chemical injection, and steam injection. This final tertiary stage uses methods that alter the original properties of the gas or oil. By increasing pressure and improving fluid flow at this stage, an additional 30 to 60% of the OOIP can be recovered.
A good way to think of the difference between IOR and EOR is that IOR pushes the hydrocarbon out of the well, while EOR alters the physical properties of the hydrocarbon so it can flow out of the well.
While hydrofracturing does not necessarily alter the physical properties of the gas, it does induce sufficient stress, to alter the condition of the target formation, and therefore, is considered an enhanced oil recovery method.
Enhanced Oil Recovery
This color-coded chart of the Weyburn oil play in Saskatchewan, Canada makes clear the role of enhance oil recovery by CO2 injection, in the production lifetime of an oil field, Figure 3.
The graph shows production over time in a way that distinguishes between various productions methods:
• the green curve designates the baseline water injection production profile from startup in 1956 to projected end of life by 2025,
• the yellow curve shows the production profile from new vertical wells drilled in 1986,
• the reddish brown curve displays the production profile from horizontal infill drilling in 1990, and
• to offset declines in production, the purple curve shows the dramatic increase in production from CO2 injection in 2000.
Like all unconventional recovery methods, CO2 injection used in the Weyburn play amplified and extended the tail of the oil field’s production profile in order to extract “stranded” oil-in-place.
Gas Recovery by Hydrofracturing
The enhanced recovery method we will discuss in detail is one used to extract natural gas from shale formations – hydrofracturing aka hydraulic fracturing, fracking or even frac.
To start with, “why is hydrofracturing required to liberate the gas from shale formations, in the first place? We will soon see that fracking is a matter of the porosity, permeability, and mechnaics of the shale formation.
Shale is a fine-grained clastic rock that forms from the compaction of silt and clay-size mineral particles that we commonly call “mud.” This composition places shale in a category of sedimentary rocks known as “mudstones”. Shale is distinguished from other mudstones because it is fissile and laminated. “Laminated” means that the rock is made up of parallel layers, about one centimeter in thickness. “Fissile” means that the rock readily splits into thin pieces along the laminations.
Black organic shales are the source rock for oil and natural gas deposits. These black shales obtain their black color from tiny particles of organic matter that were deposited with the mud, from which the shale formed. As the mud was buried under high pressure and temperature within the earth for several million years some of the organic material was transformed into oil and natural gas.
Hydraulic fracturing, which involves the injection of more than a million gallons of water, fine grain sand and chemical additives at high pressure down and across the wellbore into horizontally drilled wells, fractures, the relatively deep fissile shale layers to allow the entrapped gas to permeate out of the rock’s pores.
The horizontal and vertical fractures or fissures are held open by fine grain sand called prop-pant, because it props open the fracture. Proppant embedment increases the:
• surface area of exposed fractures, and
• desorption and mobility of the gas from the shale layer.
The result is more efficient recovery of a larger volume of the gas-in-place.
Hydrofracturing is a well-coordinated, highly technical and multistage process, Figure 4. The execution of which is sequenced to meet the particular needs of the formation. Each gas zone is somewhat different and requires a hydraulic fracturing design tailored to the particular physical properties of the formation. Therefore, while the process remains essentially the same, the sequence, injection pressure, fluid mix design and additive package may change depending on the site-specific characteristics and properties of the target formation.
The primary steps in a frack treatment, include:
1. An acid stage, consisting of several thousand gallons of water mixed with a dilute acid such as hydrochloric: This serves to clear out the wellbore of cement debris left over from the drilling stage, and to help open up, the underground shale fractures near the wellbore.
2. A pad stage, consisting of approximately 100,000 gallons of frac fluid without proppant material: The pad stage fluid then fills the wellbore and opens the formation to facilitate the flow and placement of proppant material.
3. A proppant sequence stage, which may consist of several sub-stages of fluid combined with proppant material. The proppant consists of a fine mesh sand or ceramic material, intended to keep open the fissures created, and/or enhanced, during the fracturing operation. Typical proppant sizes range from 100 µm to 2.5 mm. For example, when describing frac sand, the product is frequently referred to as the sieve cut, i.e. 20/40 sand with particle sizes between 420 µm – 840 µm.
This stage may collectively use several hundred thousand gallons of water. Proppant material may vary from a fine particle to a coarser particle throughout this sequence.
4. and a final, flushing stage, consisting of a volume of fresh water sufficient to flush the excess proppant from the wellbore.
About 10 – 30% of the fracturing fluid will be pushed out of the well by the escaping gas within the first 30 days of production. This is called flowback wastewater.
Permeability and Porosity
As previously, mentioned, conventional and unconventional reservoirs are differentiated by the relationship between permeability and pore sizes of the rock or sand, Figure 5.
Where porosity is the percent volume of the rock that is open-pore space. This determines the amount of fluid, either liquid or gas, that a rock can contain.
In sediments or sedimentary rocks, like shale, the porosity depends on grain size, the shapes of the grains, the degree of sorting, and the degree of cementation around the grains; where cementation is the formation of new minerals that encapsulate and cement the grains together. Since cements tend to fill in the pore space, highly cemented sedimentary rocks have lower porosity.
On the other hand, permeability is a measure of the degree to which the pore spaces are interconnected, and the size of the interconnections. A permeable material is, therefore, full of tiny, connected spaces that liquids and gases, can seep through.
Low porosity usually results in low permeability, but high porosity does not necessarily imply high permeability, as in the case of shale formations, which are moderately porous but relatively impermeable in its native undisturbed state.
It is possible to have a highly porous rock with little or no interconnections between pores. A good example of a rock with high porosity and low permeability is a vesicular volcanic rock, where the bubbles that once contained gas give the rock a high porosity, but since these holes are not connected to one another the rock has low permeability.
Due to low packing density, coarse-grained rocks are usually more permeable than fine-grained rocks; and sands are more permeable than clays.
The lower graph shows the permeability range and porosity of producing formations, Figure 6. Conventional reservoirs, typically sand formations are shown on the right.
These have large pores and high permeability. This allows the hydrocarbons to flow relatively unrestricted. In these cases, conventional extraction technologies, are therefore, economically viable.
However, tight sands and shale basins, shown on the left, have smaller pores. These micro-pores are more restrictive to the flow of hydrocarbons.
Extraction therefore requires advanced recovery methods, such as CO2 injection for tight oil sands and hydrofracturing for hydrocarbon bearing shale reservoirs.
Safe, efficient, and profitable development of shale gas resources depends on achieving a clear understanding of the role of fracture mechanics in gas production.
In rock mechanics, the term hydraulic fracturing is used for fluid injection operations in sealed-off borehole intervals to induce and propagate tensile fractures in the shale formation. A hydraulic fracture is therefore a pressure-induced fracture caused by injecting fluid into a target rock formation. Fluid is pumped into the formation at pressures that exceed the fracture pressure—the pressure at which rocks break.
In petroleum engineering, fracture mechanics have been used for more than 50 years. Rock fracture mechanics is about understanding what will happen to the rocks in the subsurface, when subjected to fracture stress.
Adding to the complexity of designing models that predict the behavior of fracture formation from hydrofracturing; shale layers cannot be treated as simple isotropic and homogeneous material. Their porous and fluid filled nature require that poroelastic theory, rather than less complex elastic behavior, be used for some problems, especially in the case of hydraulic fracturing.
The presence of a freely moving fluid in a porous rock modifies its mechanical response. Porous media such as shale, whose solid matrix is elastic and the fluid is viscous are poroeleastic, and characterized by its porosity, permeability as well as the properties of its constituents, both solid matrix and fluid. Information in this section obtained from PetroWiki and the Society of Petroleum Engineers (SPE).
Two mechanisms play a key role in this interaction between the interstitial fluid and the porous rock:
• an increase of pore pressure induces a dilation of the rock, and
• compression of the rock causes a rise of pore pressure; if the fluid is prevented from escaping the pore network.
There are a number of important parameters to consider in the fracturing of rock. Some of these are fracture toughness, in-situ stress, Poisson’s ratio, and Young’s modulus.
The size and orientation of a fracture, and the magnitude of the pressure needed to create it, are dictated by the formation’s in situ stress field. This stress field may be defined by three principal compressive stresses, which are oriented perpendicular to each other.
Figure 7 illustrates the local in-situ stress state at depth for an element of formation. Underground formations are confined, and under stress, from several directions, vertical (σV) and horizontal min and max, (σHmax and σHmin, respectively) as illustrated by the red arrows. The combination of these stress are the in-situ stress of the native formation.
The magnitudes and orientations of these three principal stresses are determined by the tectonic regime in the region and by depth, pore pressure and rock properties, which determine how stress is transmitted and distributed within the formation.
The three principal stresses increase with depth. The rate of increase with depth defines the vertical gradient.
The principal vertical stress (σV) commonly called the overburden stress, is caused by the weight of rock overlying a measurement point. The horizontal forces, both min and max comprise the other two principal stress components. Their vertical gradients, vary widely by basin and lithology, the characteristics of a rock are controlled by local and regional stresses, mainly through tectonics.
In situ stresses control the orientation and propagation direction of hydraulic fractures. Hydraulic fractures are tensile fractures, they open in the direction of least resistance — the minimum stress component — and propagate in the plane perpendicular to that stress.
If the minimum principal stress is in the horizontal direction, the fractures will be vertical. If the minimum principal stress is in the vertical direction, the fractures will be horizontal
In some shallow formation less than 2,000 ft., the minimum principal stress may be in the vertical direction; thus, the hydraulic fracture will be horizontal.
In reservoirs deeper than approximately 2,000 ft., the minimum principal stress will be horizontal; thus, the hydraulic fracture will be vertical.
The magnitude and direction of the principal stresses are important because they control the:
• Breakdown pressure, defined as the critical pressure to create and propagate a fracture at the tip of a pre-existing fissure, such as that formed by a natural fracture or hydrofracturing
• Shape and vertical extent of the fracture,
• Direction of the fracture, and
• Stresses trying to crush and/or embed the propping agent during production.
As previously mentioned, the minimum stress (σHmin) component is important, since in deep wells, it indicates the direction the fracture will open and propagate, that is open in the horizontal direction, fracture width, and propagate in the vertical plane, fracture height. For a vertical fracture, the minimum horizontal stress can be estimated by Equation 1.
• σHmin = the minimum horizontal stress or in-situ stress of the formation under evaluation.
• v (Poisson’s ratio) = will be discussed in more detail later in this discussion.
• σob (overburden stress) = normally about 1 psi/ft of depth.
• α (Biot’s constant) = governs the rocks poroelastic behavior.
It is defined as the ratio of the volume change of the fluid filled material to the volume change of the material when the fluid is free to move out of the rock. That is, the swelling change from the pores being filled with a fluid.
• σp = reservoir fluid pressure or pore pressure
• σext = external tectonic stress.
The tectonic stress term is important in many areas where plate tectonics or other forces increase the horizontal stresses in the formation.
Young’s Modulus and Poisson’s Ratio
In addition to the in-situ stresses, which help determine the orientation of a fracture, other rock mechanical properties are important when designing a hydraulic fracture.
These mechanical properties include both the:
• Elastic properties of the rock, which is a function of Young’s modulus, shear modulus, bulk modulus, and Poisson’s ratio, and
• Rock’s inelastic properties, such as fracture gradient and formation strength.
Poisson’s ratio is defined as the ratio of lateral expansion to longitudinal contraction for a rock under a uniaxial stress condition – that is, the ratio of lateral strain to axial strain, Figure 8. It describes the amount of lateral extension of a material that is under a vertical, axial, strain.
If a tensile load, or stretching force, is applied to a material, the material will elongate on the axis of the load, perpendicular to the stress plane, as illustrated in Figure 8 A. When the tensile stress exceeds the tensile strength of the rock, the rock fails and breaks.
Conversely, if the load is compressive, two opposing forces act on a rock; the axial dimension will decrease, as illustrated in Figure 8 B.
The compressive strength of a rock is usually much higher than its tensile strength, that is, rocks are most likely to fail under tension well before they would fail under compression. Thus, it is very important to know the stress regime, a rock will be subjected to, when designing a frac treatment.
For incompressible material such as rock, the Poisson’s ratio (v) is between 0.1 and 0.5, meaning, rocks are somewhat in-compressible.
A Poisson ratio larger than 0.5 would correspond to a material that has its volume expand when compressed, Figure 8 B. This the behavior one would expect by pushing a piece of clay.
For elastic, isotropic and homogeneous materials, a Poisson’s ratio of zero means that the material does not present lateral deformation on bending, compressing or extending; that is, it neither shrinks when stretched or balloons out when compressed.
A Poisson ratio less than -1 would correspond to a material that when compressed in a given direction, shrinks more in transverse direction.
Materials that have a Negative Poisson’s Ratio, also known as anti-rubber, and dilational materials, are materials whose lateral width increases when stretched from either end; or shrinks laterally when compressed. This behavior is counter intuitive, since most materials exhibit a positive Poisson’s Ratio when stretched from either end, their lateral width decreases. There are some exotic microporous material made from expanded poly(tetrafluoroethylene), that exhibit this mechanical behavior.
An example of the practical application of Poisson’s ratio is the cork of a wine bottle. The cork must be easily inserted and removed, yet it also must withstand the pressure from within the bottle. Rubber, with a Poisson’s ratio of 0.5, could not be used for this purpose because it would expand when compressed into the neck of the bottle and would jam. Cork, by contrast, with a Poisson’s ratio of nearly zero, is ideal in this application, meaning that it does not expand in the radial direction as it is compressed.
Poisson’s ratio can be estimated from acoustic log data or from correlations based on lithology.
The theory used to compute fracture dimensions is based on linear elasticity. When applying this theory, the modulus of the formation is an important parameter. Young’s modulus is defined as “the ratio of stress to strain for a uni-axial stress.”
Young’s modulus, sometimes referred to as modulus of elasticity is equal to the ratio of the stress acting on a substance, to the strain produced. It’s a measure of resistance to elastic deformation, or in other words, the stiffness of the material.
If the modulus is large, the material is stiff. In hydraulic fracturing, a stiff rock results in more narrow fractures. If the modulus is low, the fractures are wider. The modulus of a rock is a function of the lithology, porosity, fluid type, and other variables.
Young’s modulus can be calculated by the equation shown, or as the slope, of the straight-line portion of a stress-strain curve as shown on the right.
Table 1 presents typical ranges for Young’s modulus and Poisson’s ratio as a function of lithology, general physical characteristics of rocks. Shale exhibits the largest modulus, between 1 to 10 x 105 psi. Shale is therefore the stiffest of all the rocks shown. This implies, that hydraulic fracturing of shale will result in numerous narrow fractures.
With a Poisson ratio between 0.28 and 0.43, shale is relatively incompressible. It will then fracture under tensile stress well before failing under compression.
Fracture Formation Model
To understand how fractures form, we begin with a Fracture gradient cure shown in the lower right hand corner. This propagation model integrates several of the mechanical components previously discussed and provides estimates to predict the pressure required to hydraulically fracture a formation.
The curve, Figure 9, is from a Minifrac injection fall-off diagnostic test. The intent of a Minifrac is not only to determine the pressure when the fracture breaks open, but also the pressure when the fracture closes during the preceding fall-off period. The test is performed without proppant to allow the fractures to close.
For references, the least principal stress components and fracture planes are presented above the fracture gradient curve. The illustration shows the plane of propagation perpendicular to the min principal stress, which in deep wells is typically, σHmin, the left hand image, giving rise to fractures in the vertical plane.
The first step in setting up a fracture treatment job is to know the expected treatment rate and pressures. For a given formation there is a pressure which when applied will cause the rock to fracture.
Knowing the fracture gradient, the actual bottom-hole treating pressure, BHTP, required to fracture the rock can be calculated for a given depth. This down-hole pressure equals the surface injection pressure plus the hydrostatic pressure of the fracking fluid.
The hydrostatic pressure of the fluid, Point 1, is a function of density and vertical height of the fluid column, meaning, the pressure exerted by a fluid will increase in proportion to depth measured from the surface because of the increasing weight of fluid exerting downward force from above.
The mini frac begins, at Point 1, the hydrostatic pressure at the wellhead. As the frac fluid is pumped into the WELL-BORE, the pressure increases at a rate just sufficient to overcome the minimum principal stress component — usually the horizontal stress (σHmax) — and the tensile strength of the rock. The pressure necessary to initiate a fracture in the rock is the formation breakdown pressure, Point2.
At the surface, this is observed as a slight drop in pressure as the fluid flows into the fractured formation and extends the fractures along a plane perpendicular to the minimum principal stress, Point 3, the fracture propagation pressure.
The difference between breakdown and propagation pressures is related to the tensile strength of the rock and near-wellbore stress patterns.
After the pumps are shut down at Point 3, the initial shut-in pressure, or ISIP, is recorded at Point 4.
The initial shut-in pressure is approximately equal to the final injection pressure minus the pressure drop due to friction (ΔPfriction), between Points 3 and 4. The wellbore friction pressure loss is due to the frictional effect in the wellbore and perforations as the viscous fluid is injected. The wellbore and near-wellbore friction effects are important factors to know, when designing a fluid to minimize frictional losses in the wellbore.
The comparatively short break-down phase is followed by a much longer falloff period, starting at Point 4, which can last a few hours to several days. This falloff period provides sufficient time for the pressure to closely approach initial reservoir pressure. During the falloff period, the surface pressure at the top of the closed wellbore drops as pressures inside a fracture subsides as the fluids either flow back into the well or leak away into the reservoir rock.
This drop in pressure allows the fracture to close, Point 5. By definition, the fracture closure pressure is the pressure at the formation face, which is necessary to hold an existing fracture open, or in other words, the pressure below which fractures will not open. Closure pressure is equal to the minimum, usually horizontal, principal stress component.
Closure pressure is generally measured instead of opening pressure because it is less affected by test procedures and are easier to observe. In cases where the reopening pressure is of interest, the Minifrac is extended to Stage 2, by opening the wellbore and restarting the pumps; to re-pressurize the zone in order to find the fracture reopening pressure, Point 6. At this point, the leveling-off of the pressure indicates the fracture has reopened, allowing the fluid to flow into the fissure.
If injection is continued, the fracture propagation pressure, Point 3, can be reconfirmed.
While the Minifrac test is performed without proppant, a main stimulation treatment, with proppant, ends when the engineers have completed their planned pumping schedule or when a sudden rise in pressure indicates that a screenout has taken place. A screenout is a blockage caused by accumulation, clumping or lodging of the proppant across the fracture width that restricts fluid flow into the hydraulic fracture.
What many fail to contemplate is the relative proportions of fractures. They are truly massive in length, often reaching hundreds or even thousands of feet laterally from the wellbore, in very narrow sheets, typically less than one hundredths of a foot wide (0.01 ft.).
Fracture Design Guidelines
Now that we have a basic picture of the principals of fracture formation and propagation, we will now take an empirical view of the fracture treatment. Here we will consider the components of the surface pressure during a hydraulic fracturing treatment. The surface pressure must exceed the pressure required to break the rock. The surface pressure must be higher due to frictional pressure loses from the pipe and perforations and the change in hydrostatic pressure, due to the increasing weight of fluid exerting a downward force from the surface.
Surface pressure, Psurf, can therefore, be calculated by Equation 2:
Psurface = BHTP + ΔPfriction + Δ Pperf + ΔPnet – ΔPhydrostatic
Equation 2: Surface Pressure Equation
• BHTP = Bottomhole Treating Pressure (Frac Gradient x Depth)
Recalling that the fracture gradient is a measure of how the pressure required to fracture rock in the earth changes with depth,
• ΔPfriction = Treating pipe friction pressure at the injection rate
• Δ Pperf = Friction pressure through perforations, that is, the pressure loss as the fracturing fluid passes through the restricted flow area of the perforations.
• ΔPnet = Excess pressure over frac pressure required to extend the fracture
• Δ Phydrostatic = the Hydrostatic pressure, which is determined from the density changes of the fracturing fluid with depth of the wellbore.
These variables can be determined by laboratory measurements, Minifracs, and other base calculations.
For the purpose of this example, the treatment procedure follows one called limited entry. This completion technique will be discussed in more detail later in this discussion. Also, due to time constraints, several other critical factors are omitted from this presentation, such as well drilling, casing and cementation, perforating the production zone, zonal isolation, and perforation phasing, just to name a few.
Also, keep in mind that the effectiveness of the process depends directly upon “back pressure” or perforation friction generated in the wellbore throughout the treatment due to a pre-determined rate/perforation relationship. In this fracturing process, perforation friction is desirable during the entire treatment. Best results, are therefore, obtained by maintaining preformation friction at a maximum during treatment.
To conceptualize what goes on during a limited entry completion, think of an ordinary garden hose fitted with a spray nozzle. When the nozzle is fully open, the water tends to pour out gently in large quantities. However, when the nozzle is closed down by restricting the opening, the water sprays out fast, far and hard. Whether fully open or closed down, the water pressure going to the nozzle is the same, but the back-pressure increases as the diameter of the opening is reduced. In addition, the same nozzle can be adjustable to deliver different spray patterns.
The procedure for setting up a Limited Entry treatment is from “Comments Concerning Limited Entry Treatment Applications,” by Alfred R. Jennings, Jr., PE – Enhanced Well Stimulation, Inc.
First, using the derived value of surface pressure (Psurf) from the equation shown in the previous slide, we can then calculate the value of perforation friction pressure (ΔPperf), to be allocated for the limited entry back-pressure.
It cannot be overstated that limited entry completion relies on the perforation friction pressure, to control the stimulation fluid distribution into each perforated interval, Figure 11.
Figure 11: Hydraulic Fracture Dynamics
Next, we can calculate, Q, the flow rate per perforation by the Orifice Flow Equation 3:
Q = D2 C √ΔP/ρ / 0.487
Equation 3: Orifice Flow Equation
D = 0.42 inches (average diameter of perforations)
C = 0.95 (coefficient of roundness of jet perforation)
ΔPperf = 280 psi;
ρ = 8.33 lb/gal (density of frac fluid)
Using these values shown for: D, C, and ΔPperf we obtain a perforation flow rate of:
2.0 BPM/perf (barrels per minute per perforation).
Then, using, 2.0 BPM/perf, we can determine the injection rate for the Limited Entry fracturing treatment.
Table 2 shows the number of perforations, the right column, and several possible injection rates, the left column, possible for the various rates.
For example, if it’s decided to form 20 perfs in the first interval, then at 2.0 BPM/perf, the total injection rate is 2 times 20 or 40 barrels per min, which equal 28 gal/sec or 106 L/sec.
Finally, based on the pay zones and desirable distribution of the fracturing treatment, the perforations can be specified for the completion
In this example, using the previous calculated values, the hydraulic fracturing operation will consist of a:
• Total injection rate of 40 BPM over 20 perforations at 2 BPM per perf
• Perforation friction pressure of 280 psi
• Perforation diameter of 0.42 inches (11 mm)
• Perforation phasing of 180 degrees.
This figure shows the distribution of perforations for this frac treatment.
In this case, the 20 perforations are distributed over 3 clusters in a non-uniform pattern:
• first cluster, shown on the bottom of the illustration, receives 4 perfs at 8 barrels per minute for 20% of the treatment,
• second cluster, in the middle, receives 10 perfs at 20 barrels per minute for 50% of the treatment,
• and third and last cluster, on the top, receives 6 perfs at 12 barrels per minute for the remaining 30% of the treatment.
When designing a frac job, there are 3 areas that that also require, detailed planning in order to maximize production and economics:
• Fracture Conductivity
Conductivity is vital during the flowback and cleanup of fracture fluids and the long term productivity of the well.
• Fracture Fluid Mix Design
The frac fluid must be designed with the proper chemical additives and concentrations to achieve optimum fracture dimensions, proppant transport and embedment.
• Fracture Placement
The frac fluid must be properly placed to achieve the desired output.
The first consideration and the primary characteristic of a hydraulic fracture that provides any economic benefit is a conductive fracture that economically increases production.
In other words, the primary goal of a hydraulic fracture is to create a highly conductive flowpath.
Like electrical conductivity, which is dependent on the flow of elections, conductivity in shale formations is a function of the flow of gas out of a fracture.
Conductivity (Cf) is a measure of the fracture’s ability to transmit fluids
Cf = kf x Wf
Equation 4: Fracture Conductivity Equation
The conductivity of a fracture is calculated by kf the permeability of the gas within the fracture, times Wf the width of the fracture.
Effective Conductivities and Damage Mechanisms
Effective can be Less than 1% of API/ISO test values, Figure 13. Even though a proppant is added to the frac fluid, hydraulic fractures are not ideal and proppant packs are subject to damage and conductivity degradation from disappointingly short fractures of limited flow through. This results in lower than expected production.
Figure 13 shows the reduction in conductivity of two proppants due to several damage mechanisms. Jordan sand is represented by the brown columns and a light weight ceramic proppant by the red columns.
Figure 13: Effective Conductivities and Damage Mechanisms
The starting point is obtaining laboratory measurements of conductivity. These reference measurements are shown by the two columns on the far left. After reducing the conductivity to account for non-Darcy flow (non-lamina flow), multiphase flow, reduced proppant concentration, gel damage, fines and cycle stress, there can be as much as a 98% reduction in baseline conductivity, shown on the right.
Fluid systems optimized to reduce these damage mechanisms will minimize fracture degradation and maximize the productivity of the well.
Fracture Fluid Mix Design
As we seen, the fracturing fluid properties are critical to the creation and propagation of the fracture. Proper fluid design is necessary to protect the integrity of the geological formation and improve the production of natural gas – allowing the frac to be performed in a safe and efficient manner.
The current practice for hydraulic fracturing treatments of shale gas reservoirs is to apply a sequenced pumping event; in which millions of gallons of a water-based fracturing fluid, mixed with proppant and chemical additives, is injected in a controlled and monitored manner, into the target shale formation, above the fracture breakdown pressure. The additives are selected to impart a predictable set of fluid properties, including viscosity, friction, formation-compatibility, and fluid-loss control.
The fluid is injected at high pressures, up to 9,000 psi, into the well to create conductive fractures and bypass near-wellbore damage in hydrocarbon-bearing zones. The net result is an expansion in the productive surface-area of the reservoir, compared to the unfractured formation.
The hydraulic fluid mix designs are highly complex and confounded by the need to perform multiple engineered functions. The ideal fracturing fluid should be:
• Easy to control
• Able to transport the propping agent in the fracture
• Compatible with the formation rock and fluids
• Generate enough pressure drop along the fissure to create a wide fracture
• Minimize friction pressure losses during injection
• Exhibit controlled-break to a low-viscosity fluid for cleanup after the treatment
• Safe and Efficacious.
Furthermore, the hydraulic fluid must also take into consideration:
• Baseline Data and Damage Mechanisms
• Fluid Rheology for effective fracture initiation and propagation
• Formation Geology
• Reservoir Temperature
• Reservoir Pressure
• Expected Value Of Fracture Half-Length, which we have not spoken about;
• Water Sensitivity
• Environment, Health and Public Safety
• Cost of Additives & Commodity Market Prices
The litany of functions and requirements for something happing potentially miles below the surface in a perforated hole about ½ inch in diameter is hardly a trivial matter and a highly technical task.
The composition of fracturing fluids varies from one geologic basin or formation to another. The fracturing fluid is a proprietary mixture consisting of at least 98% water and sand with the remaining 2%, or less, of chemical additives, each having a specific function. Typically, there are no more than 12 additives used in the fracturing process depending on the characteristics of the water and the shale formation being fractured.
This Hydraulic Fracturing Fluid Component Information and Disclosure Sheet from FracFocus.org, is site specific, and gives general information about the well along with specific chemical data for all materials used to frac the particular well. The chemical data includes the trade name of each ingredient, supplier, purpose of the ingredient, its chemical name, CAS number (Chemical Abstract Services), and percent mass prior to and after mixing with the water.
This particular disclosure sheet is for the well drilled and fracked in the Barnett shale play, Tarrant County, Texas right under my house in Arlington, Texas within the DFW Metroplex with a population of 1.2 million. In my particular case, the operator, Chesapeake Energy, drilled down 8,348 vertical feet and required approximately 4 and a ½ million gallons of water to complete the well.
The fracking fluid consisted of, by weight:
• Giving a total water concentration of 89.47%
88.89% fresh water
0.58% water from the HCl (hydrochloric acid)
• Total proppant concentration of 10.15%
• Total water and proppant concentration of 99.64%
• Slightly more than one third of one percent (0.36%) of 6 chemical additives of which non-aqueous HCl was the primary component at one tenth of one percent (0.10%) .
The predominant fluids currently being used for fracture treatments, in the gas shale plays, are water-based fracturing fluids called “slickwater” because they contain friction-reducing additives. The addition of friction reducers “slick” the water to minimize friction between fluid and pipe, allowing the fracturing fluid and proppant to be pumped into the target zone at a higher rate and reduced pressure due to the reduction in frictional forces between the wellbore and the propagating fracture.
This chart shows the type of additive, its purpose and a representative compound.
In addition to friction reducers, other additives may include:
• Biocides to prevent microorganism growth and to reduce biofouling of the fractures and the production of corrosive byproducts, which can inhibit the flow of gas.
• Acids to help dissolve minerals and initiate cracks in the rock.
• Breakers, either oxidizing or enzymatic, to reduce the viscosity of the frac fluid, to allow delayed breakdown of the gel and to react with the crosslinker and gel once in the formation making it easier for the fluid to flow to the borehole;
• Clay Stabilizers to prevent formation clays from swelling, which can inhibit the flow of gas out of the fissures
• Corrosion Inhibitors to prevent corrosion of the pipe
• Crosslinking Agents to maintain fluid viscosity as temperature increases
• Gelling Agents to thicken the water in order to suspend and transport the proppant
• Iron Control Chemicals to prevent precipitation of the metal in the pipe
• pH Adjusting Agents to maintain the effectiveness of other components, such as crosslinkers
• Scale Inhibitors to prevent scale deposits downhole and in surface equipment that can reduce the flow of gas out of the fissures.
• Surfactants to increase the viscosity of the fracture fluid
Overall, the ideal fracturing fluid must enhance production over the life of the well with little or no risk to public safety and the environment.
To ensure that fractures stay open, engineers inject additional materials, depending on lithology of the formation. In sandstone or shale formations, they inject proppant to hold the fractures open.
Some say, the ideal proppant is lighter than air, stronger than diamonds and cheaper than dirt. In short, It does not exist. So how is a proppant selected?
Figure 14 shows several types of proppant, all about 1 mm in diameter. Going clockwise from the top, proppants include, silica sand, either Brady Brown or Ottawa White; a high-strength light-weight ceramic sand made from sintered bauxite referred to as, HSB, for high strength bauxite; and resin-coated silica either pre-cured or curable, referred to as RCS for resin coated sand. Not shown is a newer type of proppant that combines light-weight and high strength through the use of nano-structuring, which at this time, is somewhat pricy.
To start the selection process, we begin with crush resistance – the closure pressure that proppant will be subjected to and the desired conductivity at that stress, Figure 15. Engineers generally select proppant based on the in situ closure stress or pressure on the proppant, and other factors such as the reservoir temperature and pressure drawdown; where drawdown is the differential pressure that drives fluids from the reservoir into the wellbore. The proppant must be capable of handling that stress to prevent crushing, deformation and fine migration, Figure 15. Proppant that crushes under formation pressure either allows the fracture to close or produces fines that reduce conductivity and hydrocarbon flow. Suitable proppant must consider the potential to embed in the fracture, especially in softer rock
Furthermore, a low specific-gravity or lightweight proppant is particularly important to allow the slickwater frac to transport the proppant deep into the fracture system and prevent premature settling. Spherical proppant typically handles higher stress better than non-spherical sands, and smaller proppants tend to spread farther into the fractures and provide superior conductivity.
Overall, companies look for a low specific gravity proppant with high strength to flow deep into the fractures and still hold the fracture open under high pressure at the lowest cost.
Many companies use Ottawa sand more than any other proppants. It is more spherical and more crush resistant than Brady Sand and is less expensive than ceramics or resin-coated sands.
This calculation of in-situ closure stress allows engineers to select more appropriate proppant.
The value of minimum stress on the proppant, (σprop), equals the fracture gradient (gf) multiplied by true vertical depth, TVD, plus the reservoir pressure minus flowing bottomhole pressure, FBHP.
By taking into consideration not only the in situ closure stress on the proppant in the fracture; but also the reservoir and flowing buttonhole pressure, Equation 5 ensures that the proppant strength will never be less than the closure pressure or minimum horizontal stress of the formation. A proppant selected in this manner with an upper strength that exceeds the forces acting on it, will withstand the pressure with a low risk of ever being crushed by the formation. In this way, the downhole support by proppant will provide an efficient conduit for production of fluid from reservoir to wellbore, thereby, increasing conductivity and output.
σprop = (gf X D) + (pr – pwt) = (0.70 x 10,000) + (5,000 – 3,000) = 9,000 psi.
Equation 5: Proppant Pressure Calculation
• Well depth = 10,000 ft (TVD)
• Fracture Gradient (gf) = 0.70 psi/ft
• Reservoir Pressure (pr) = 5,000 psi
• FBHP (pwt) = 3,000 psi.
Figure 16 presents a proppant selection flow chart based on the maximum stress on the propping agent. If the maximum effective stress is less than 6,000 psi, then the figure recommends that sand be used as the propping agent. If the maximum effective stress is between 6,000 and 12,000 psi, then either a Resin-Coated Sand (RCS) or intermediate-strength proppant (ISP) be used, depending on the temperature. For cases in which the maximum effective stress is greater than 12,000 psi, high-strength bauxite should be used as the propping agent.
The flow chart is only a guide, because there will be exceptions. For example, even if the maximum effective stress is less than 6,000 psi, the engineer may choose to use RCS or other additives to “lock” the proppant in place when proppant flowback becomes an issue. In high-flow-rate gas wells, non-Darcy pressure drops can lead to the use of ceramic proppants to maximize fracture conductivity.
The final consideration in the completion process is placement.
The main objective of all stimulation efforts is to increase the productivity index of a producing well, which defines the rate at which oil or gas can be produced at a given pressure differential between the reservoir and the wellbore. That is to make the best well, compatible with cost.
Since the early 2000s, advances in drilling and completion technology have made horizontal wellbores much more economical. Horizontal wellbores allow far greater exposure to a formation than conventional vertical wellbores. This is particularly useful in shale formations, which do not have sufficient permeability to produce economically with a vertical well. Such wells, when drilled onshore, are now usually hydraulically fractured in a number of stages, referred to as multistage completion.
The method by which the fractures are placed along the wellbore is most commonly achieved by one of two methods, known as “plug and perf” and “sliding sleeve”.
The wellbore for a plug and perf job is generally composed of standard joints of steel casing, cemented or uncemented, set in the drilled hole. Once the drilling rig has been removed, a wireline truck is used to perforate near the end of the well, and then fracturing fluid is pumped. This process is repeated in what are known as stages. Then the wireline truck sets a plug in the well to temporarily seal off that section, and then perforate the next section of the wellbore. Another stage is then pumped, and the process is repeated along the horizontal length of the wellbore.
The wellbore for the sliding sleeve technique is different, in that the sliding sleeves are included at set spacing in the steel casing at the time it is set in place. The sliding sleeves are usually all closed at this time. When the well is due to be fractured, using one of several activation techniques, the bottom sliding sleeve is opened and the first stage gets pumped. Once finished, the next sleeve is opened which concurrently isolates the first stage, and the process repeats.
These completion techniques may allow for more than 30 stages to be pumped into the horizontal section of a single well if required, which is far more than would typically be pumped into a vertical well.
Well performance has proven that both of these objectives can be fulfilled by a properly designed multistage treatment either convention or limited entry treatment.
Today, Limited-Entry Completion is a preferred method to place fractures in the wellbore. Limited-entry begins where conventional multistage leaves off. Limited entry fracturing has proven to be an effective stimulation method for horizontal wells with multiple zones of different pressure or thick pay sections with an acceptable level of cost and risk.
Limited entry limits the number of perforations in each perforated interval and uses perforation friction pressure to control the stimulation fluid distribution into each interval. The number of perforations are limited to cause high downhole pressures which result in simultaneous stimulation of zones with different closure pressures.
The simultaneous treatment of multiple perforated intervals by Conventional Multi-stage methods is depicted in Figure 17. Three zones, A, B and C, each with a continuous cluster of perforations and different bottom-hole fracture pressures are opened up in the same interval of the wellbore. A 73 foot internal may contain as many as 146 perforations spaced a 2 perfs per foot. Note, information shown in Figures 17 to 19, may be outdated and used for demonstrations purposes only.
Even if the bottom hole treating pressure is raised above the fracture initiation pressure of each successive zone to be treated, the zone which offers the least fracture resistance will take the treatment; in this case Zone B with a BHTP of 3800 psi. Zones A and C with bottom hole pressures of 4,200 and 4,000 psi, respectively, remain untreated. Zone B will continue to take the treatment until a diverting method is successfully utilized, such as bridge plugs, temporary plugging agents or ball sealers.
Therefore, to treat more than one zone, the bottom hole treating pressure must be raised above the fracture initiation pressure of each successive zone to be treated.
Figure 18 shows the perforation friction pressure varies directly with the flow rate through the perforation.
Therefore, by increasing the injection rate, the perforation friction will be increased. The perforations act as individual bottom-hole chokes. In this manner, these so-called chokes create an increase in available bottom-hole pressure as the injection rate is increased.
Limited entry treatment illustrated by Figure 4, take advantage of this by:
• limiting the number and diameter of the perforations, and
• providing a sufficient injection rate, to restrict the capacity of the perforations.
This restriction increases the pressure in the wellbore, and thereby, diverts the treatment to the other zones, until all zones are equally fractured.
The process of breaking down each successive zone occurs rapidly, since maximum pressure and rates are established early in the treatment. With adequate injection rate at the surface, this process is continued until either all of the perforated zones are fractured or the maximum permissible pressure on the casing is reached.
Best results are obtained by maintaining perforation friction at a maximum during treatment. This insures treatment of all perforated intervals that will accept fluid within the permissible casing pressure limitations. It is recognized that all the perforations could be treated at a lesser injection rate. However, this would not be true if the bottom-hole fracture pressure of the individual zones vary significantly. Therefore, to have the most assurance that all zones are being treated, an injection rate that will give a maximum permissible wellbore pressure is necessary.
Small-diameter perforations are preferred in limited entry treatments to:
• increase perforation friction, and
• lower hydraulic horsepower requirements.
Figure 19 shows that, for the same perforation friction, approximately twice as much fluid can be injected through a ½” perforation as through a 3/8” hole. Therefore, by using the small perforations, less hydraulic horsepower is required to deliver an injection rate adequate to maintain a maximum perforation friction.
If the engineer selects too many perfs for a limited entry treatment, the velocity of the fluid would decline at the risk of proppant settling or screen out. If too few perfs are performed, the overall injectivity would be restricted, causing an increase in hydraulic horsepower and cost.
Limited Entry fracturing is based on the premise that every perforation will be in communication with a hydraulic fracture and will be contributing fluid during the treatment at the pre-determined rate. Therefore, if any perforation does not participate, then the incremental rate/perf of every other perforation is increased, resulting in higher perforation friction. Therefore, it is important that the perforations be placed to facilitate the Limited Entry fracturing process as much as possible.
I hope this discussion was not overly confusing, but fulfilled my objective and improved your understanding of hydraulic-fracturing and have a better appreciation for the complexity and technical sophistication of the process. It is by no mean haphazard and reckless and not reminiscent of Berlioz’ Symphonie Fantastique Fifth movement: “Dreams of a Witches’ Sabbath.”
Unconventional oil recovery will play a critical role in tomorrow’s oil industry, as existing asset production rates and volumes dwindle and exploration capital is further stressed.
Planning and coordinating multiple services, understanding baseline conditions, adjusting for realistic conditions and designing multi-functional fluids are critical elements for project success.
Integrating the various services into a seamless operation requires up-front planning to determine the appropriate technology and chemical options required for a low-risk, safe and productive operation.