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Tight gas reservoirs

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Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs.

Tight gas reservoirs have one thing in common—a vertical well drilled and completed in the tight gas reservoir must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Normally, a large hydraulic fracture treatment is required to produce gas economically. In some naturally fractured tight gas reservoirs, horizontal wells and/or multilateral wells can be used to provide the stimulation required for commerciality.

To optimize the development of a tight gas reservoir, the geoscientists and engineers must optimize the number of wells drilled, as well as the drilling and completion procedures for each well. Often, more data and more engineering manpower are required to understand and develop tight gas reservoirs than are required for higher permeability, conventional reservoirs. On an individual well basis, a well in a tight gas reservoir will produce less gas over a longer period of time than one expects from a well completed in a higher permeability, conventional reservoir. As such, many more wells (or smaller well spacing) must be drilled in a tight gas reservoir to recover a large percentage of the original gas in place (OGIP), when compared to a conventional reservoir.

Definition of tight gas

In the 1970s, the United States government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0.1 md. This definition was a political definition that has been used to determine which wells would receive federal and/or state tax credits for producing gas from tight reservoirs. Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy’s law.

The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated—normally by a large hydraulic fracture treatment. Eq. 1 illustrates the main factors controlling flow rate. Eq. 1 clearly shows that the flow rate, q, is a function of permeability k; net pay thickness h; average reservoir pressure p¯; flowing pressure pwf; fluid properties β¯μ¯ drainage area re; wellbore radius rw; and skin factor s. Thus, to choose a single value of permeability to define "tight gas" is not wise. In deep, high pressure, thick reservoirs, excellent completions can be achieved when the formation permeability to gas is in the microdarcy range (0.001 md). In shallow, low pressure, thin reservoirs, permeabilities of several millidarcies, might be required to produce the gas at economic flow rates, even after a successful fracture treatment.


The best way to define tight gas is that "the reservoir cannot be produced at economic flow rates nor recover economic volumes of natural gas unless a special technique is used to stimulate production." Specifically, large hydraulic fracture treatments, a horizontal wellbore, or multilateral wellbores must be used to stimulate flow rates and increase the recovery efficiency in the reservoir.

So what is a typical tight gas reservoir? There are no "typical" tight gas reservoirs. They can be:

  • Deep or shallow
  • High pressure or low pressure
  • High temperature or low temperature
  • Blanket or lenticular
  • Homogeneous or naturally fractured
  • Single layered or multilayered

The optimum drilling, completion and stimulation methods for each well are a function of the reservoir characteristics and the economic situation. Some tight gas reservoirs are in south Texas, while others are in the deserts of Egypt. The costs to drill, complete and stimulate the wells, plus the gas price and the gas market affect how tight gas reservoirs are developed. As with all engineering problems, the technology used is a function of the economic conditions surrounding the project.

Resource triangle

The concept of the resource triangle was used by Masters and Grey to find a large gas field and build a company in the 1970s.[1] The concept is that all natural resources are distributed log-normally in nature. If you are prospecting for gold, silver, iron, zinc, oil, natural gas, or any resource, you will find that the best or highest-grade deposits are small in size and, once found, are easy to extract. The hard part is finding these pure veins of gold or high permeability gas fields. Once you find the high-grade deposit, producing the resource is rather easy and straightforward. Fig. 1 illustrates the principle of the resource triangle.

As you go deeper into the gas resource triangle, the reservoirs are lower grade, which usually means the reservoir permeability is decreasing. These low permeability reservoirs, however, are much larger in size than the higher quality reservoirs. The scale on the right side of Fig. 1 illustrates typical values of formation permeability for tight gas sands or carbonates. Other low quality resources, such as coalbed methane, gas shales, and gas hydrates would likely have different permeability scales.

The common theme is that low quality deposits of natural gas require improved technology and adequate gas prices before they can be developed and produced economically. However, the size of the deposits can be very large when compared to conventional or high quality reservoirs. The concept of the resource triangle applies to every hydrocarbon-producing basin in the world. One should be able to estimate the volumes of oil and gas trapped in low quality reservoirs in a specific basin by knowing the volumes of oil and gas that exist in the higher quality reservoirs.

Tight gas in the United States

Since the 1950s, the oil and gas industry has been completing and fracture treating low permeability wells in the United States. However, it was the natural-gas price increase in the 1970s that spurred significant activity in low permeability gas reservoirs. Since the 1970s, sustained increases in natural gas prices, along with advances in evaluation, completion and stimulation technology, have led to substantial development of low quality gas reservoirs. Fig. 2 is a map showing the location of the major tight gas basins in the United States.

The estimates of gas production, reserves, and potential from the tight gas basins in the United States are compatible with the concept of the resource triangle. Fig. 3 illustrates the tight gas resource base estimates from the Gas Technology Institute (GTI).[2] The gas produced through the year 2000 from tight gas reservoirs is estimated to be 58 Tcf. Proven reserves in tight gas reservoirs are 34 Tcf. Thus, the sum of produced gas plus proven reserves adds up to 92 Tcf. GTI estimates the volume of technically recoverable gas from known U.S. tight gas accumulations at 185 Tcf. The term "technically recoverable" means that the gas is known to exist; the technology is available to drill, complete, stimulate and produce this gas; but the gas cannot be booked as reserves until the wells are drilled and the reservoirs are developed. The next category in Fig. 3 is called undiscovered, which represents the GTI estimate of gas that is likely to be discovered in known tight gas basins. Finally, the largest category is called resources. This value represents the gas in place in the U.S. tight gas basins. Substantial improvements in technology or changes in the gas market are required before the gas in the resources category can be produced economically.

Fig. 4 illustrates world natural gas reserves by area. These estimates are available to everyone from the BP website: Notice that most of the gas is in eastern Europe, the former Soviet Union, and the Middle East. Fig. 5 shows the gas reserves for six selected countries. Russia has 1,700 Tcf of gas reserves, while Iran has 812 Tcf. Notice that the United States has only 167 Tcf of proven gas reserves, of which 34 Tcf are from tight gas reservoirs. The last bar on the graph shows the sum of the estimates of technically recoverable tight gas and undiscovered tight gas in the United States as estimated by GTI.[2] Summing all three categories of tight gas (proven, technically recoverable, and undiscovered), one could expect that 569 Tcf of gas will be produced in the future from tight gas reservoirs in the United States, which is substantially more than the 133 Tcf (167–34) of proven gas reserves that are currently booked for conventional gas reservoirs.

Some people believe that producing natural gas from unconventional reservoirs is not important now, but could likely be important in the future. Actually, significant production from unconventional gas is occurring in the United States. Production from tight gas is important to both the natural gas consumer and the producer. During the later part of the 1900s, there were approximately 85,000 producing tight gas wells; 29,000 producing gas shale wells; and 10,000 producing coalbed methane wells. The following statistics indicate the importance of these unconventional wells to the gas produced and consumed in the United States for the year 1999.

  • Gas consumption in the United States = 21.8 Tcf.
  • Gas production (net) in the United States = 18.8 Tcf.
  • Gas production from tight reservoirs = 3.4 Tcf.
  • Gas production from shales = 0.4 Tcf.
  • Gas production from coal seams = 1.2 Tcf.

As these statistics indicate, 15.6% of the consumption and 18.1% of the gas production in the United States came from tight gas reservoirs. If one considers all three unconventional reservoir types, then 23% of consumption and 25% of production came from unconventional reservoirs. The logical conclusion is that tight gas reservoirs were very important to the United States in 1999 and will be even more important in coming decades.

Tight gas outside the United States

The purposes for discussing tight gas in the United States in such detail are to provide statistics to validate the resource triangle concept and to provide information on how important tight gas production currently is to the United States. The next logical question is to ask, "Can we extrapolate what we know about tight gas in the United States to the other oil and gas basins around the world?" The answer is yes. The resource triangle concept is valid for all natural resources in all basins in the world, so it is logical to believe that enormous volumes of gas in unconventional reservoirs will be found, developed, and produced in every basin that now produces significant volumes of gas from conventional reservoirs. Unfortunately, no organization has published a comprehensive review and estimate of the volume of gas that might be found in tight reservoirs around the world. In fact, the volume of gas in conventional reservoirs around the world is still being revised upward as exploration for natural gas increases.

If we use the concept of the resource triangle, the volume of gas-in-place in tight reservoirs could be orders of magnitude higher than the volume of gas known to exist in conventional reservoirs, in every basin. The information in Fig. 4 shows that the current estimate of world gas reserves is about 5,250 Tcf. By comparing the ratio of current conventional gas reserves in the United States (133 Tcf) to the potential for gas production from tight reservoirs in the United States (569 Tcf), one could envision that eventually 20,000+ Tcf of gas will be produced from tight reservoirs around the world, given proper economic conditions and technology improvements.

Without question, interest in tight gas reservoirs around the world increased substantially during the 1990s. In many countries, tight gas is defined by flow rate and not by permeability. During the past decade, development activities and production of gas from tight reservoirs have occurred in:

  • Canada
  • Australia
  • Mexico
  • Venezuela
  • Argentina
  • Indonesia
  • China
  • Russia
  • Egypt
  • Saudi Arabia

Large hydraulic fracture treatments are being used more commonly around the world to stimulate gas flow from low permeability reservoirs. Such activity will only increase in the coming decades.

Geologic considerations

The analysis of any reservoir, including a tight gas reservoir, should always begin with a thorough understanding of the geologic characteristics of the formation. The important geologic parameters for a trend or basin are:

  • The structural and tectonic regime
  • The regional thermal gradients
  • The regional pressure gradients

Knowing the stratigraphy in a basin is very important and can affect:

  • Drilling
  • Evaluation
  • Completion
  • Stimulation

Important geologic parameters that should be studied for each stratigraphic unit are:

  • The depositional system
  • The genetic facies
  • Textural maturity
  • Mineralogy
  • Diagenetic processes
  • Cements
  • Reservoir dimensions
  • Presence of natural fractures

According to Fisher and McGowan,[3] a depositional system is a group of lithogenetic facies linked by depositional environment and associated processes. Each lithogenetic facies has certain attributes, including porosity, permeability, and special relations to other facies, that affect the migration and distribution of hydrocarbons. The nine principal clastic depositional systems reviewed by Fisher and Brown[4] can be classified into three major groups, as illustrated in Table 1. According to the information from GTI,[2] most tight gas sandstones that are being developed and produced in the United States are located in barrier-strandplains, deltaic systems, or fluvial systems. A few plays are found in shelf and fan delta systems. Knowing the depositional system is important because it will affect the reservoir morphology and both the lateral and vertical continuity one expects in a reservoir. Details concerning clastic depositional systems can be found in books by Galloway and Hobday[5]and Berg.[6]


When most sands are deposited, the pores and pore throats are well connected, resulting in high permeability. As explained by Berg, [6] sands are composed of mineral particles called grains, which usually consist of quartz, feldspars, and rock fragments. The finer particles between the grains are called matrix. The original porosity and permeability of a sandstone is determined by characteristics such as mineral composition, pore type, grain size, and texture. After deposition and burial, the grains and matrix are commonly altered by the physical effects of compaction and by chemical changes. These changes are broadly referred to as diagenesis. Table 2 describes common diagenetic changes as explained by Berg.[6]

Reservoir continuity

One of the most difficult parameters to evaluate in tight gas reservoirs is the drainage area size and shape of a typical well. In tight reservoirs, months or years of production are normally required before the pressure transients are affected by reservoir boundaries or well-to-well interference. As such, the engineer often has to estimate the drainage area size and shape for a typical well in order to estimate reserves. Knowledge of the depositional system and the effects of diagenesis on the rock are needed to estimate the drainage area size and shape for a specific well.

In blanket, tight gas reservoirs, the average drainage area of a well largely depends on the number of wells drilled, the size of the fracture treatments pumped on the wells, and the time frame being considered. In lenticular or compartmentalized tight gas reservoirs, the average drainage area is likely a function of the average sand-lens size or compartment size, and may not be a strong function of the size of the fracture treatment.

A main factor controlling the continuity of the reservoir is the depositional system. Generally, reservoir drainage per well is small in continental deposits and larger in marine deposits. Fluvial systems tend to be more lenticular. Barrier-strandplain systems tend to be more blanket and continuous. If one looks at the tight gas plays that have been more successfully developed, such as the Vicksburg in south Texas, the Cotton Valley Taylor in east Texas, the Mesa Verde in the San Juan Basin, and the Frontier in the Green River Basin, just to name a few, all of these sandstones are marine deposits. Marine deposits tend to be more blanket and continuous. Most of the more successful tight gas plays are those in which the formation is a thick, continuous, marine deposit.

There are other formations, such as the Travis Peak in east Texas, the Abo in the Permian Basin, and the Mesa Verde in parts of the Rocky Mountains that are fluvial systems and tend to be very lenticular. The Wilcox Lobo in south Texas is highly compartmentalized because of faulting. In lenticular or compartmentalized reservoirs, the drainage area is controlled by the geology and must be estimated by the geologist or engineer.

The best way to determine the depositional system is to cut and analyze cores. Cutting cores in the shales, mudstones, and nonreservoir rock above and below the main pay interval is recommended. A geologist can tell much more about the depositional system by studying the entire stratigraphic sequence. The core descriptions can be correlated with openhole logging data to determine the logging signature for various depositional environments. Once these correlations are made, logs from additional wells can be analyzed to generate maps of the depositional patterns in a specific area. These maps can be useful in developing field optimization plans.

Regional tectonics

Tectonic activity during deposition can affect:

  • Reservoir continuity
  • Morphology

In addition, regional tectonics affect the horizontal stresses in all rock layers. The horizontal stresses, in turn, affect:

  • Faulting
  • Rock strength
  • Drilling parameters
  • Hydraulic fracture propagation
  • Natural fracturing
  • Borehole stability

The main concerns for tight gas reservoirs are the effects of regional tectonics on hydraulic fracture propagation and natural fracturing in the formation.

Natural fractures affect both the overall level of permeability in a reservoir and the degree of permeability anisotropy in the reservoir. If a reservoir is naturally fractured, it is possible that a horizontal well or multilateral wellbores will be more effective in producing gas than a vertical well with a hydraulic fracture. If a fracture treatment is performed in a reservoir containing an abundance of natural fractures, problems with multiple hydraulic fractures near wellbore, tortuosity problems, and excessive fluid leakoff can occur during the fracture treatment.

The engineer and geologist should work together to understand the current and past tectonic activity in a basin. Knowledge of the tectonic history is important in designing the field optimization plan and developing drilling and completion procedures. A good way to begin is to study the fault systems in a basin. Hydraulic fractures tend to parallel normal faults and run perpendicular to reverse faults. The engineer should use data from openhole caliper logs, injection tests, and prior hydraulic fracture treatments to better understand the total in-situ stresses and the tectonic stress component in a given area. By combining engineering data with geologic data, a team of geologists and engineers can develop an understanding of the regional tectonics in an area. This understanding is important to the analysis and development of any tight gas reservoir.

Reservoir considerations

Normally, a tight gas reservoir can be described as a layered system. In a clastic depositional system, the layers are composed of:

  • Sandstone
  • Siltstone
  • Mudstone
  • Shale

In carbonate systems, layers are composed of:

  • Limestone
  • Dolomite
  • Shale
  • Possibly halite or anhydrite

To optimize the development of a tight gas reservoir, a team of geoscientists, petrophysicists, and engineers must fully characterize all the layers of rock above, within, and below the pay zones in the reservoir.

The following data are required to use 3D reservoir and fracture propagation models to evaluate the formation, design the fracture treatment, and forecast production rates and ultimate recovery:

  • Gross pay thickness
  • Net pay thickness
  • Permeability
  • Porosity
  • Water saturation
  • Pressure
  • In-situ stress
  • Young’s modulus

The speed at which pressure transients move through porous media is a function of the:

  • Formation permeability
  • Fluid viscosity
  • Fluid compressibility
  • Other variables

In a high permeability gas reservoir (say, 100 md), a pressure transient will reach the reservoir boundary in a matter of hours or days. Well-to-well interference in high permeability, blanket gas reservoirs is quite common. However, in a gas reservoir with a permeability of 0.1 md, the pressure transients move 1,000 times slower than the transients in a 100-md reservoir. As such, it might take years of production before well-to-well interference or a boundary can be recognized by studying pressure transient or production data.

In high permeability gas reservoirs, the semisteady-state form of Darcy’s law works well. Methods such as the McGuire and Sikora[7] graph and Prat’s[8] equations can be used to design and analyze hydraulic fractures in medium to high permeability gas reservoirs. Short (24 to 72 hours) pressure buildups, analyzed using a Horner graph,[9] can provide accurate estimates of formation properties in medium to high permeability gas reservoirs.

However, in tight gas reservoirs, semisteady-state analysis methods cannot be used alone to analyze short-term (days, weeks or months) data. The best methods for analyzing transient production or pressure data are:[10][11][12]

  • Type curves
  • Analytical models
  • Finite-difference models

Transient flow analyses can be used to estimate values of:

  • Formation permeability
  • Skin
  • Fracture half-length
  • Fracture conductivity
  • Minimum value of drainage area

Drilling and completion considerations

The most important part of drilling a well in a tight gas reservoir is to drill a gauge hole. A gauge hole is required to obtain an adequate suite of openhole logs and to obtain an adequate primary cement job. In low porosity, shaly reservoirs, the analyses of gamma ray (GR), spontaneous potential (SP), porosity, and resistivity logs to determine accurate estimates of shale content, porosity, and water saturation can be difficult. If the borehole is washed out ("out of gauge"), the log readings will be affected, and it will be even more difficult to differentiate the pay from the nonpay portions of the formation. If the borehole is washed out, obtaining a primary cement seal is difficult, which could affect zonal isolation and cause the well to have to be cement squeezed prior to running tests or pumping stimulation treatments.

Formation damage and drilling speed should be a secondary concern. Some wells are drilled underbalanced to increase the bit penetration rate or to minimize mud filtrate invasion. However, if the wellbore is severely washed out because the well was drilled underbalanced, it is probable that a lot of money will be wasted because the logs are not accurate and the primary cement job might not be adequate. It is best to drill a tight gas well near balanced to minimize borehole washouts and mud filtrate invasion.

The completion strategy and stimulation strategy required for a tight gas reservoir very much depends on the number of layers of net gas pay and the overall economic assessment of the reservoir. In almost every case, a well in a tight gas reservoir is not economic to produce unless the optimum fracture treatment is both designed and pumped into the formation. The well can be perfectly drilled, cased, and perforated, but will be uneconomic until the optimum fracture treatment is pumped. As such, the entire well prognosis should be focused on how to drill and complete the well so that it can be successfully fracture treated. The hole sizes, casing sizes, tubing sizes, wellhead, flowlines, and perforation scheme should be designed to accommodate the fracture treatment.

Formation evaluation

To properly complete, fracture treat, and produce a tight gas reservoir, each layer of the pay zone and the formations above and below the pay zone must be thoroughly evaluated. The most important properties that must be known are pay zone thickness, porosity, water saturation, permeability, pressure, in-situ stress, and Young’s modulus. The raw data that are used to estimate values for these important parameters come from:

  • Logs
  • Cores
  • Well tests
  • Drilling records
  • Production from offset wells

Because tight gas reservoirs are normally also low porosity reservoirs, the importance of detailed log analyses becomes critical to understanding the reservoir. For example, if an error of 2 porosity units (p.u.) occurs when the porosity is 30%, it is normally not critical. The difference between 28 or 30% porosity will not lead to much error in net gas pay, water saturation, or gas in place. However, the same 2 p.u. error applied to a reservoir in which the porosity is 8% is a much more significant problem. The difference between 6 and 8% porosity can cause significant errors in estimates of net gas pay, water saturation, and gas in place. As such, careful preprocessing of log data and detailed petrophysical analyses of all openhole logging data are very important in the analyses of tight gas reservoirs.


  1. Masters, J.A. 1979. Deep Basin Gas Trap, Western Canada. AAPG Bulletin 63 (2): 152.
  2. 2.0 2.1 2.2 Tight Gas Resource Map of the United States. Gas Technology Inst. Report, GTI-01/0114, Quicksilver Resources. Cite error: Invalid <ref> tag; name "r2" defined multiple times with different content Cite error: Invalid <ref> tag; name "r2" defined multiple times with different content
  3. Fisher, W.L. and McGowen, J.H. 1969. Depositional Systems in the Wilcox Group of Texas and Their Relationship to Occurrence of Oil and Gas. AAPG Bulletin 53 (1): 30.
  4. Fisher, W.L. and Brown, L.F. Jr. Clastic Depositional Systems—A Genetic Approach to Facies Analysis. Bur. Econ. Geol. University of Texas at Austin.
  5. Galloway, W.E. and Hobday, D.K. 1983. Terrigeneous Clastic Depositional Systems. New York City: Springer-Verlag.
  6. 6.0 6.1 6.2 6.3 Berg, R.R. 1986. Reservoir Sandstones. New Jersey: Prentice-Hall, Inc.
  7. McGuire, W.J. and Sikora, V.J. 1960. The Effect of Vertical Fractures on Well Productivity. J Pet Technol 12 (10): 72-74. SPE-1618-G.
  8. Prats, M. 1961. Effect of Vertical Fractures on Reservoir Behavior—Incompressible Fluid Case. SPE J. 1 (2). SPE-1575-G.
  9. Horner, D.R. 1951. Pressure Build-Up in Wells. Proc., Third World Petroleum Congress, Leiden, Sec. II, 503.
  10. Lee, W.J. and Holditch, S.A. 1981. Fracture Evaluation With Pressure Transient Testing in Low-Permeability Gas Reservoirs. J Pet Technol 33 (9): 1776–1792. SPE-9975-PA.
  11. Cinco-Ley, H., Samaniego-V., F., and A.N., D. 1978. Transient Pressure Behavior for a Well With a Finite-Conductivity Vertical Fracture. SPE J. 18 (4): 253–264. SPE-6014-PA.
  12. Agarwal, R.G., Carter, R.D., and Pollock, C.B. 1979. Evaluation and Performance Prediction of Low-Permeability Gas Wells Stimulated by Massive Hydraulic Fracturing. J Pet Technol 31 (3): 362–372. SPE-6838-PA.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

Online multimedia

Cox, Stewart. 2013. Effects of Complex Reservoir Geometries and Completion Practices on Production Analysis in Tight Gas Reservoirs.

External links

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See also

Tight gas drilling and completion

Modeling tight gas reservoirs

Log analyses in tight gas reservoirs

Core analyses in tight gas reservoirs

Reserves estimation in tight gas reservoirs

Permeability estimation in tight gas reservoirs

Statistical data correlations in tight gas reservoirs

Hydraulic fracturing in tight gas reservoirs