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Production of Coalbed CBM

Mar 24, 2015

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Page 1: Production of Coalbed CBM

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Report on latest model of Production of Coal Bed Methane (CBM)

Submitted by

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Table of Contents:

Cover Page…………………………………………………………………………………………...1

Table of contents…………………………………………………………………………………….. 2

1. Introduction…………………………………………………….............................................................3

1.1 Coal bed Methane………………………………………….............................................................3

1.2 What is CBM………………………………………………............................................................3

1.3 Adsorption Process………………………………………………………………………………..3

1.4 Why CBM- Increasing demand for CBM………………….............................................................3

1.5 Areas with Coal bed Methane………………………………………………………………….....4

2. CBM Extraction……………………………………………………………………………………....4

2.1Coal Bed Methane extraction process……………………………………………………………..4

2.2Permeability of coal bed methane reservoirs……………….............................................................4

2.3Intrinsic properties affecting gas production……………………………………………………....5

3. Production of CBM...........................................................................................................................…...6

3.1 Production Behavior of CBM Reservoirs….......................................................................................6

4. CBM Production models……………………………………………………………………………….7

4.1 Reservoir Cartesian base model……………………………………………………………………7

4.2 Mathematical modeling of CBM production and CO2 sequestration in coal seams….………........9

References…………………………………………………………………………………………………12

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1. Introduction:

1.1 Coal bed Methane:

Once a nuisance and a safety hazard, coalbed natural gas (CBNG)—also referred to as coalbed methane (CBM)—has become a valuable

part of a nation’s energy portfolio. CBNG production has increased during the last 15 years and now accounts for about a twelfth of U.S.

natural gas production. As America’s natural gas demand grows substantially over the next two decades, CBM will become increasingly

important for ensuring adequate and secure natural gas supplies for the United States.

1.2 What is CBM?

Coalbed methane (CBM) or Coal Bed Methane is a form of natural gas extracted from coal beds. The term refers to methane adsorbed

into the solid matrix of the coal. It is called 'sweet gas' because of its lack of hydrogen sulfide.

The primary energy source of natural gas is a substance called methane (CH4). Coal bed methane (CBM) is simply methane found in

coal seams.

The presence of this gas is well known from its occurrence in underground coal mining, where it presents a serious safety risk. Coalbed

methane (CBM) is distinct from typical sandstone or other conventional gas reservoir, as the methane is stored within the coal by a

process called adsorption. The methane is in a near-liquid state, lining the inside of pores within the coal (called the matrix). The open

fractures in the coal (called the cleats) can also contain free gas or can be saturated with water.

Unlike much natural gas from conventional reservoirs, coalbed methane contains very little heavier hydrocarbons such as propane or

butane, and no natural gas condensate. It often contains up to a few percent carbon dioxide. Some coal seams, such as those in certain

areas of the Illawarra Coal Measures in NSW, Australia, contain little methane, with the predominant coal seam gas being carbon

dioxide.

1.3 Adsorption Process:

Adsorption is the adhesion of atoms, ions, biomolecules or molecules of gas, liquid, or dissolved solids to a surface. This process creates

a film of the adsorbate (the molecules or atoms being accumulated) on the surface of the adsorbent. It differs from absorption, in which a

fluid permeates or is dissolved by a liquid or solid. The term sorption encompasses both processes, while desorption is the reverse of

adsorption. It is a surface phenomenon.

1.4 Why CBM- Increasing demand for CBM:

Methane (natural gas), while perhaps most closely related in our minds with petroleum, also occurs in association with coal, the most

abundant fossil fuel resource.

Conservative estimates suggest that Twenty-four percent of the energy consumed in the U.S. in 2000 was natural gas. Use of natural gas

nationwide increased 22 percent during the last decade, and this trend is projected to continue. Natural gas is the fastest growing energy

source for electricity generation. Resources of Coalbed Methane (CBM) are reported as between 3,500 and 9,500 Tcf contained in

subsurface coal seams around the world, with anywhere from 1,000 to 3,000 Tcf in North America alone. The exploitation of CBM has

been steadily progressing in the United States because of the proximity of resources and improved finding and transporting mechanisms.

Annual production from 11 coal basins now exceeds 1.5 Tcf, 10% of the annual gas production.

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1.5 Areas with coalbed methane:

Worldwide coalbed methane (CBM) reserves have been estimated at 84 ~ 262 trillion m3 (2,980 ~ 9,260 trillion ft3). The majority of

these CBM reserves are mainly located in Russia (17 ~ 113 trillion m3), Canada (6 ~ 76 trillion m3), China (30 ~ 35 trillion M3),

Australia (8 ~ 14 trillion m3), and USA (11 trillion m3). In the United States, CBM accounted for 10% of dry gas reserves and 8% of dry

gas production in 2003(2). In other countries, such as China, Canada, and Australia, CBM projects are attracting more and more attention

by resource companies.

Fig 1.1- Worldwide CBM Reserves

2. CBM Extraction:

2.1 Coalbed Methane extraction process:

Since CBM travels with ground water in coal seams, extraction of CBM involves pumping available water from the seam in order to

reduce the water pressure that holds gas in the seam. CBM has very low solubility in water and readily separates as pressure decreases,

allowing it to be piped out of the well separately from the water. Water moving from the coal seam to the well bore encourages gas

migration toward the well.

To extract the gas, a steel-encased hole is drilled into the coal seam (100–1500 meters below ground). As the pressure within the coal

seam declines due to natural production or the pumping of water from the coalbed, both gas and 'produced water' come to the surface

through tubing. Then the gas is sent to a compressor station and into natural gas pipelines. The 'produced water' is either reinjected into

isolated formations, released into streams, used for irrigation, or sent to evaporation ponds. The water typically contains dissolved solids

such as sodium bicarbonate and chloride.

2.2 Permeability of coal bed methane reservoirs:

Permeability is key factor for CBM. Coal itself is a low permeability reservoir. Almost all the permeability of a coal bed is usually

considered to be due to fractures, which in coal are in the form of cleats and joints. The permeability of the coal matrix is negligible by

comparison. Coal cleats are of two types: butt cleats and face cleats, which occur at nearly right angles. The face cleats are continuous

and provide paths of higher permeability while butt cleats are non-continuous and end at face cleats. Joints are larger fractures through

the coal that may cross lithological boundaries. Hence, on a small scale, fluid flow through coal bed methane reservoirs usually follows

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rectangular paths. The ratio of permeabilities in the face cleat direction over the butt cleat direction may range from 1:1 to 17:1. Because

of this anisotropic permeability, drainage areas around coal bed methane wells are often elliptical in shape.

2.3 Intrinsic properties affecting gas production:

Porosity

The porosity of coal bed reservoirs is usually very small, ranging from 0.1 to 10%.

Adsorption capacity

Adsorption capacity of coal is defined as the volume of gas adsorbed per unit mass of coal usually expressed in SCF (standard cubic feet,

the volume at standard pressure and temperature conditions) gas/ton of coal. The capacity to adsorb depends on the rank and quality of

coal. The range is usually between 100 to 800 SCF/ton for most coal seams found in the US. Most of the gas in coal beds is in the

adsorbed form. When the reservoir is put into production, water in the fracture spaces is pumped off first. This leads to a reduction of

pressure enhancing desorption of gas from the matrix.

Fracture permeability

As discussed before, the fracture permeability acts as the major channel for the gas to flow. The higher the permeability, higher is the gas

production. For most coal seams found in the US, the permeability lies in the range of 0.1 to 50 milliDarcies. The permeability of

fractured reservoirs changes with the stress applied to them. Coal displays a stress-sensitive permeability and this process plays an

important role during stimulation and production operations.

Thickness of formation and initial reservoir pressure

The thickness of the formation may not be directly proportional to the volume of gas produced in some areas.

For Example: It has been observed in the Cherokee Basin in Southeast Kansas that a well with a single zone of 1–2 ft of pay can produce

excellent gas rates, whereas an alternative formation with twice the thickness can produce next to nothing. Some coal (and shale)

formations may have high gas concentrations regardless of the formation's thickness, probably due to other factors of the area's geology.

The pressure difference between the well block and the sand face should be as high as possible as is the case with any producing

reservoir in general.

Other properties

Other affecting parameters include coal density, initial gas phase concentration, critical gas saturation, irreducible water saturation,

relative permeability to water and gas at conditions of Sw = 1.0 and Sg = 1-Swirreducible respectively.

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3. Production of CBM:

3.1 Production Behavior of CBM Reservoirs:

Production behavior of CBM reservoirs completely diverges from the conventional gas reservoirs. In conventional gas reservoirs, the

production rate declines with time while in coalbed methane reservoirs production inclines until it reaches a peak and then it declines.

Initially water occupies the fracture (cleat) system in the reservoir, and flows to the well. The reservoir must be dewatered first in order to

produce gas from the coal. The production can be divided in three phases that are shown in Figure 3.1.

During phase I the reservoir is considered water saturated in the natural cleat system, which requires water to be produced to depressurize

the coal and produce gas. Ideally, water production will relieve the hydraulic pressure on the coal in order to start the production by

desorption of the gas from the coal. This process is known as Dewatering. The number of days of this dewatering process and the amount

of produced water can vary widely. The gas is produced at very low rates during this phase .This phase is characterized by a constant

water production rate and a declining flowing bottomhole pressure. At the end of this first phase, the well has reached its minimum

flowing bottomhole pressure.

In phase II, the gas production rate increase until it reaches the maximum value, which is called peak gas rate. During this phase, the

water production rate begins to decline as the coal is dewatered. The dewatering period for coals can take from weeks to years. During

phase II some changes in the reservoir flow conditions occur. The water relative permeability decreases, while gas relative permeability

increases. The outer boundary effects become significant.

Limit between phase II and phase III is established when the peak gas rate is reached. During phase III, the conditions are stable. A

typical decline trend defines the behavior of the gas production. During this phase, water production is low or insignificant. The water

and gas relative permeability’s do not change extensively. The pseudo-steady state exists for the rest of producing life.

Figure 3.1: Typical Coalbed Methane Production Profiles for Gas and Water Rates (Adopted from GRI)

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There are some physical reservoir properties that control the length of the dewatering process and the magnitude of the producing rates of

gas and water. Those physical reservoir properties are:

1. The spacing and connection of the fracture system, which are defined by the permeability.

2. The amount of gas stored in the coal, which is defined by the absorbed gas content.

3. The interactions between gas and water, which are defined by the relative permeability.

4. The tendency of the coal organic matrix to release stored gas, which is defined by the diffusion coefficient and the desorption

isotherm.

4. CBM Production Models:

The production methods of CBM include conventional pressure depletion production and enhanced coalbed methane (ECBM) recovery.

At present, CBM is mainly recovered by the former method. In ECBM, gases such as N2, CO2, or flue gas are injected to displace

methane and maintain coalbed pressure. This recovery method is still in its infancy with only two field-scale ECBM projects (one

injected N2 and the other injected CO2), and one singlewell pilot project worldwide.

Productivity evaluation and prediction are important steps in the development of CBM reservoirs. Because gas storage mechanisms in

coal seams (mainly adsorbing on the walls of pores) are different from that in conventional gas reservoirs (compressed in pores),

conventional reservoir simulators generally do a poor job in predicting CBM production.

Over the past decade, many models have been developed to characterize CBM production processes. Commercial simulators for CBM

production can be categorized into two types: Modified conventional black oil simulators and Modified compositional simulators.

With the recognition of the stress dependency of coal permeability and porosity and shrinkage/swelling of the coal matrix due to

desorption/adsorption, some simulators have been modified to accommodate these characteristics. However, in these simulators the

influence of in situ stresses is simplified with an analytic model or a monotonic relation between the permeability ratio and pressure

changes. Durucan et al. developed a finite element model to simulate the in situ stress changes near wellbores and coupled the stress

changes with fluid flow simulation by characterizing dynamic changes in permeability.

Listed below are some of the latest models used in production of CBM:

4.1 Reservoir Cartesian base model:

A two-dimensional Cartesian (CBM base) model was developed for an under-saturated CBM reservoir with a well located at the center

of the drainage area.

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Fig 4.1: Cartesian CBM Base Model

The reservoir simulation software used in this study was GEM developed by the Computer Modeling Group (CMG) 18. GEM is CMGs

advanced general equation of state, compositional, dual porosity reservoir simulator. Capable of modeling both coal and shale gas

reservoirs. GEM includes options for gas sorption in the matrix, gas diffusion through the matrix, two phase flow through the natural

fracture system.

The reservoir parameters used to develop the base model are summarized in the table below (Table 1). The simulation runs were made by

varying several of the key parameters over the ranges provided in Table 1. The results were compiled into a database containing large

number water production histories.

Type curves for CBM Reservoir base model:

In order to develop type curves, two set of dimensionless rate and time were defined for water.

The water dimensionless rate and time were defined similarly as:

In the above equations, represents the initial (maximum) water rate and is the initial water in the cleat system which can be calculated by

the following equation:

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Where, A is the reservoir area in acres, h is the thickness of coal in ft, is the cleat system porosity and is the initial cleat system

water saturation.

The base water production histories were converted to dimensionless rate and time using above definitions and the results were plotted

both Cartesian and log-log scale.

Table 1: Values and Ranges of Parameters Used in the CBM Reservoir Base Model

4.2 Mathematical modeling of CBM production and CO2 sequestration in coal seams

Sequestration of carbon dioxide (CO2) in unmineable coal seams has been proposed as one of the geologic strategies to mitigate

increasing concentrations of CO2 in the atmosphere. Coal seam sequestration of CO2 is particularly attractive in those cases where the

coal contains large amounts of methane (CH4). In these cases, not only the CO2 is stored in the coal seam in an adsorbed state but the

coalbed methane (CBM) can also be produced to generate revenue that offsets the expense of sequestration.

A mathematical model was developed to predict the coal bed methane (CBM) production and carbon dioxide (CO2) sequestration in a

coal seam accounting for the coal seam properties. The model predictions showed that, for a CBM production and dewatering process,

the pressure could be reduced from 15.17 MPa to 1.56 MPa and the gas saturation increased up to 50% in 30 years for a 5.4 × 105 m2 of

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coal formation. For the CO2 sequestration process, the model prediction showed that the CO2 injection rate was first reduced and then

slightly recovered over 3 to 13 years of injection, which was also evidenced by the actual in seam data. The model predictions indicated

that the sweeping of the water in front of the CO2 flood in the cleat porosity could be important on the loss of injectivity. Further model

predictions suggested that the injection rate of CO2 could be about 11 × 103 m3 per day; the injected CO2 would reach the production

well, which was separated from the injection well by 826 m, in about 30 years. During this period, about 160 × 106 m3 of CO2 could be

stored within a 21.4 × 105 m2 of coal seam with a thickness of 3 m.

Fig 4.1shows a schematic representation of the coal seam sequestration of CO2. As depicted in the figure, the CO2 is captured from the

flue gases in a coal firing power plant and injected into the coal seam. Upon injection,CO2 is expected to flow through the coal cleat

system and be stored within the coalmatrix.

Fig. 4.2. A schematic representation of the coal seam sequestration of CO2.

Fig 4.3 The layout for a coal seam

Type Curves for mathematical model CBM production:

Coalbed methane wells often produce at lower gas rates than conventional reservoirs, typically peaking at near 300,000 cubic feet

(8,500 m3) per day (about 0.100 m³/s), and can have large initial costs. The production profiles of CBM wells are typically characterized

by a "negative decline" in which the gas production rate initially increases as the water is pumped off and gas begins to desorb and flow.

A dry CBM well is similar to a standard gas well.

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The methane desorption process follows a curve (of gas content vs. reservoir pressure) called a Langmuir isotherm. The isotherm can be

analytically described by a maximum gas content (at infinite pressure), and the pressure at which half that gas exists within the coal.

These parameters (called the Langmuir volume and Langmuir pressure, respectively) are properties of the coal, and vary widely. A coal

in Alabama and a coal in Colorado may have radically different Langmuir parameters, despite otherwise similar coal properties.

As production occurs from a coal reservoir, the changes in pressure are believed to cause changes in the porosity and permeability of the

coal. This is commonly known as matrix shrinkage/swelling. As the gas is desorbed, the pressure exerted by the gas inside the pores

decreases, causing them to shrink in size and restricting gas flow through the coal. As the pores shrink, the overall matrix shrinks as well,

which may eventually increase the space the gas can travel through (the cleats), increasing gas flow.

The potential of a particular coalbed as a CBM source depends on the following criteria:

a) Cleat density/intensity : cleats are joints confined within coal sheets. They impart permeability to the coal seam. A high cleat density

is required for profitable exploitation of CBM.

b) The maceral composition : maceral is a microscopic, homogeneous, petrographic entity of a corresponding sedimentary rock. A high

vitrinite composition is ideal for CBM extraction, while inertinite hampers the same.

c) The rank of coal : A vitrinite reflectance of 0.8-1.5% has been found to imply higher productivity of the coalbed.

d) The gas composition : Natural gas appliances are designed for gas with a heating value of about 1000 BTU (British thermal units) per

cubic foot, or nearly pure methane. If the gas contains more than a few percent non-flammable gases such as nitrogen or carbon

dioxide, either these will have to be removed or it will have to be blended with higher-BTU gas to achieve pipeline quality. If the

methane composition of the coalbed gas is less than 92%, it may not be commercially marketable.

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REFERENCES

1. Computer Modeling Group, Inc. (2003). “Tutorial: Building, running, and analyzing Coalbed methane model using Builder and

GEM”.

2. Modeling of coal bed methane (CBM) production and CO2 sequestration in coal seams- International Journal of Coal Geology.

3. SPE International SPE91482 - Type curves for coalbed Methane Production prediction.

4. Author: Donna Garbutt, Oilfield Services Solutions Manager, Schlumberger UNCONVENTIONAL GAS- White Papers,

Online:http://www.oilfield.slb.com/media/services/solutions/reservoir/uncongas_whitepaper.pdf

5. Editor - Glen Collins “COALBED METHANE -- A MAJOR NEW ENERGY SOURCE AND AN ENVIRONMENTAL

CONCERN” The Public Lands Foundation (PLF)PAPER- #24