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| Fig. 1: Map of US shale gas plays. (Source: EIA [1]) |
The recent emerging of Shale gas technology into the energy market has demanded a recalculation of the world's natural gas reserves. The production of methane from unconventional resources, shale in particular, has become a hot table topic in many countries that have potential for high unconventional resource such as USA and Canada. According to the EIA, the shale gas map in US, Fig. 1, highlights several major active shale proved reserves such as Barnett, Woodford, Fayetteville and Haynesville-Bossier. [1] For example, Barnett shale, according to Schlumberger, the world’s largest oilfield services company, has a gross thickness that ranges between 100 ft and more than 1000 ft and holds about 50 bcf to 200 bcf of gas per square mile. [2]
The shale gas resource in the U.S. holds about 500 to 780 TCF of natural gas. [3] The prices of natural gas play important roles in governing the shale gas exploitation. As they increase the introduction of new technologies and practises increases as well. The recent advent of hydraulic fracturing technology and horizontal drilling had raised the investments in shale gas exploration and development. In the U.S., shale gas production jumped from 1% of the gas well gas production to 20% in the last 10 years. [4] Fig. 2 shows a dry natural gas total technically recoverable resources chart for US in 2007 from EIA. [5]
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| Fig. 2: Total Technical Recoverable Natural Gas Resources for US in 2007. (Source: EIA [5] |
The unconventional resources, as the plot shows, are the second highest provider of natural gas in US on 2007.
In basic words, shale gas is the natural gas that resides in a fine-grained sedimentary rock, known as shale. The shale gas is a hydrocarbon source rock and contains a rich organic matter. Anaerobic bacteria transform it after series of interactions into kerogen which is a polymeric organic compound. [6] Further increase of formation’s pressure and temperature exerts a series of reaction on kerogen with the mixed fine grained sediments and eventually transforms kerogen to liquid petroleum. More extensive heating and burial effects on the liquid petroleum converts it, ultimately, to methane gas and graphite. [6]
This type of formations is known as unconventional reservoir. Unlike conventional reservoirs, the unconventional ones are tight and have ill-defined, dispersed areal extent. [7] They are very assorted and difficult to classify. The ability of gas to flow in shale is limited to naturally existing fractures which do not assess the economics of shale gas production. [8] Therefore, technologies such as hydraulic fracturing and horizontal drilling are necessary to increase the gas production rate through fracturing and increasing the reservoir porosity and permeability to gas.
Shale formations exist deep below the surface and therefore undergo high rock compressibility due to the great overburden pressure subjected on them. It is no surprise, therefore, for shale to have tight porosity and permeability values. Geologically, shale formation may contain several natural fractures extended along the areal section but usually insufficient for economical gas production. The only mean to produce shale gas in commercial volumes is to stimulate gas wells through creating hydraulic fractures within the shale matrix to increase gas productions from subsurface. These fractures create highly conductive paths for oil and gas to chase, and therefore, become recoverable.
The components used in hydraulic fracturing are fracturing fluids and proppants. The fracturing fluids are the one used to carry the proppants and fracture the system upon injecting them at pressure high enough to create fractures in the formation and place the proppants inside them. [9] Depending on reservoir conditions, sensitivities and economics, the fracturing fluids can be either water soluble polymers such as polysaccharide guar or oil based fluids such as aluminum phosphate esters combined with hydrocarbon. [10,11] The objective of combining the water or oil with another fluid is to raise the fluids viscosity and allow them to carry the proppants to the fracture.
The main steps in hydraulic fracturing are, as mentioned in reference, fracturing, extending and maintaining the fractures. [12] Fractures are initiated by pumping selected fluids into the intended formation at a rate higher than the fluids can leak off into the formation. The high rate of fluid injection builds up a fluid pressure high enough to overcome the compressive pressure consolidating rock particles, and it therefore disrupts rock cementation and creates fractures. Notice that good information about status of in-situ stresses in the formation would help in easing the fracturing job by creating one perpendicular to the minimum horizontal stress. Therefore, to fracture a formation the injection pressure must exceed the minimum stress σc given by [9]
where Ko is a constant related to the rock properties, σv is the vertical stress representing the overburden pressure, pr is the reservoir pore pressure and T is a factor that accounts for tectonic effects on the stress. [9] The injection pressure must be high enough to overcome not only the in-situ stress but also the friction losses during the injection. The flowing pressure is measured at the bottom hole using bottom hole gauges. Fig. 3 shows the pressure points in a well and the geometry of the created fracture.
Fractures are intended to grow and extend deeper in the matrix as the injection fluids keep penetrating new areas. The rate of escape into the matrix starts to increase but the growth of the fractures continues as long as the injection rate is higher than the fluid leak rate. Thus one expects, after a certain time of injection, to have created a complex network of fractures along the matrix. The most critical part of the operation comes after creating and extending these fractures. If the fluid injection simply stopped, the fractures would close due to the high overburden pressure and the desired conduits would diminish. [12] Maintaining the fractures thus requires first injecting propping agents ("proppants"), usually sands, with the injected fluids. Then when the injection stops, the fluids flow back to the well and the propping agents remain in the fractures. The fractures do start to close, but the propping agents keep them open sufficiently to work. This way the fractures are maintained and the highly conductive paths are preserved. [9] Proppants are materials made from sand, ceramic [13] or resin-coated proppant [9] that have enough strength to survive the fracture closure pressure. They should be pumped at sufficient concentrations to fill in the whole volume of the fracture. They are usually spherical and have typical sizes some of which are 12/20, 20/40, 40/70 mesh. [14]
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| Fig. 3: Fracture geometry in a wellbore. |
The flow of fluids, whether in reservoir matrix or fracture, is governed by Darcy's law. The only difference between the two is the geometry of the medium through which the fluid flows. The Darcy equation is
where q is the flow rate in m3/s, k is the effective permeability of the fracture medium in m2 (often specified in mD, where 1 Darcy = 10-12 m2), h is the pay thickness in m, μe is the gas viscosity in Pa-s, A is the flow area in m2, δp is pressure drop in Pa and L is the length of the slit in m. Notice that some of the injected fluids would be lost in the formation but the majority would contribute to the fracturing as long as the injection rates are kept high. To know the rate of gas flowing in the fracture, knowledge of fracture geometry is essential. (See Fig. 3.) The fracture geometry includes height, width and length. Once the geometries are known, the volume of the fracture can be calculated and hence the rate of gas produced through it.
Once a zone is targeted for a fracturing job and an initial estimate of how much gas initially exists in place, the fracture volume would be equivalent to the injected fluids volume plus the proppants. Usually some bottom hole gauges are used to measure pressure, temperature and flow rates at the bottom of the well with respect to time. From the pressure vs. time graph, the time in which the fracture occurs would be indicated by a fall of pressure after buildup for a certain time. This is known as transient pressure analysis.
When a fracture is created, the geometry of the fracture would be filled with the proppants. The flow rate of gas produced for radial fracture geometry with no skin effect is given by [9]
| q | = | 2 π k h (p - pwf)
&mue ln(r/rrw) |
where r is the radial distance in m, rw is the wellbore radius in m, k is the permeability in mD, h is the fracture height in m, p is the reservoir pressure in Pa, pwf is the flowing pressure in well in Pa and μe is the viscosity of gas in Pa-s. Gas would keep producing as long as p-pwf is high enough to justify the process economics. The volume of fluids injected in m3 is given by
Here hf is the average height of the fracture in meters, usually determined by gamma ray logging, w is the average width of fracture in meters and L is the fracture length in meters. Notice that the volume of fluids would include the proppants as well.
Shale gas reserves are expected to add large volumes of natural gas to the world. Several countries such as U.S. and Canada have started producing from these reservoirs. Major shale gas plays, in U.S., are Barnett, Woodford, Fayetteville and Haynesville-Bossier. Barnett shale produces the largest volumes of gas compared to the other shale gas plays. The technological advancements in the geo-mechanics of hydraulic fracturing and horizontal drilling made the extraction of gas from shale attractive. Yet, gas prices play a major proportional role in implementing these technologies.
© Khalid Rashid Alnoaimi. The author grants permission to copy, distribute and display this work in unaltered form, with attribution to the author, for noncommercial purposes only. All other rights, including commercial rights, are reserved to the author.
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