This paper gives a detailed description of Coalbed Methane reservoirs and also few case studies have been presented highlighting the physical aspects of the reservoir. A generalized material balanced equation that accounts for and incorporates the Langmuir isotherm, initial free gas, water expansion and formation compaction. This particular form of material balancing can be used to estimate the original gas in place and unlike other methods does not require an iterative process to solve the equations. Also this report documents the practical application of the proposed material balanced equation. This report also shares case histories and best practices developed from designing and placing the cement successfully in Coalbed methane wells in India. These case histories include cement design considerations and special cement placement techniques. Reservoir models that incorporate the unique flow and storage characteristics of CBM reservoirs have been developed to study the production and decline characteristics of the reservoir. Further production facilities described include artificial lift, wellhead separation, gathering systems, compression, gas treating and water disposal. Finally we conclude the report by use of reservoir simulation to diagnose the causes of reduced well production efficiency.
|Coalbed methane reservoirs; Material balance equation;
Spacer system design
|Coalbed Methane is in its second wave of development throughout
the world. Twenty years ago it was an unconventional gas play most
operators stayed away from. The development of coal gas fields has
come as a result of favorable economic conditions, due to strong
cooperative efforts among industry and research and development
organizations in sharing technical information and experience. The
presence of large amount of free gas accumulations in abandoned
coalmines have motivated numerous operators to drill and produce
coal gas from abandoned coalmines. Roughly 100 coalmines have been
drilled in the past few decades and although not all have produced,
apparently enough gas is being produced to provide energy for small
|The term “coal” refers to sedimentary rocks that contain more than
50% by weight and more than 70% by volume of organic materials
consisting mainly of carbon, hydrogen, and oxygen in addition to
inherent moisture. Coals generate an extensive suite of hydrocarbons
and non-hydrocarbon components. Although the term “methane” is
used frequently in the industry, in reality the produced gas is typically
a mixture of C1, C2, traces of C3 and heavier, N2 and CO2. Methane, is
of special interest because, it is usually present in high concentration,
in coal, depending on composition, temperature, pressure, and other
factors and of the many molecular species entrapped within coal,
methane can be easily liberated by simply reducing the pressure in the
|Coalmine wells are located where underground mining has
occurred at depth. Targeted mine void generally are 200ft to 500ft
deep and range from 5-15ft in thickness, depending upon the seam
thickness. The amount of gas produced from the coalmine wells is
variable because gas production volumes are not reported to state,
specific details are not available. Also the composition of the mine
gas is variable and in addition to methane includes nitrogen, oxygen, butane, propane, ethane and carbon-di-oxide in varying amounts.
The heating value varies with gas composition and is generally lower
than 900 BTU. Moisture content is high causing condensation in lines.
Reservoir pressure in abandoned mines is low, averaging 4-5psig and
fluctuates with changes in biometric pressure.
|Sensitivity studies showed that most important parameters for
establishing production are permeability, initial desorption pressure
and drainage area. Production of Coalbed methane is wide spread in
United States of America.
|The major difference between a conventional and a Coalbed
reservoir is the cleat system. Cleats are the natural fractures in Coalbed
reservoirs, providing the majority of permeability and porosity from
these reservoirs (Figure 1).
|Cleats are of two types: face cleats and butt cleats. Face cleats
are those fractures providing openings nearly parallel to the surface
tangent. Butt cleats are fracture openings perpendicular to the face. The
cleat system forms a drainage mechanism for the methane gas, which
is helpful while producing but challenging while drilling or cementing
through these systems.
|Coal has a unique and complicated reservoir characteristic. It is a
heterogeneous and anisotropic porous medium which is characterized
by two (dual) distinct porosity systems, micropores and macropores,
|Primary porosity system: The matrix primary porosity system
in these reservoirs is composed of very fine pores “micropores” with
extremely low permeability. These micropores contain a large internal
surface area on which substantial quantities of gas may be adsorbed.
With such low permeability, the primary porosity is both impermeable
to gas and inaccessible to water. However, the desorbed gas can flow
(transport) through the primary-porosity system by the diffusion
process. These micropores are essentially responsible for most of the
porosity in coal.
|Secondary porosity system: The secondary porosity system
(macropores) of coal seams consists of the natural-fracture network
of cracks and fissures inherent in all coals. The macropores, known
as cleat, act as a sink to the primary porosity system that provide the
permeability for fluid flow.
|The gas production in a coalbed methane reservoir
| ➢ Removal of water from the coal cleats and lowering the reservoir
pressure to that of the gas desorption pressure. This process is called
dewatering the reservoir.
|➢ Desorption of gas from the coal internal surface area
|➢ Diffusion of the desorbed gas to the coal cleat system
|➢ Flow of the gas through fractures to the wellbore.
|A Generalized Material Balance Equation for Coalbed
|A generalized Material Balance Equation (MBE) that accounts
for and incorporates the Langmuir isotherm, initial free gas, water
expansion, and formation compaction. This particular form of material
balancing can be used to estimate the original gas-in-place and, unlike
other methods, does not require an iterative process to solve the
equations involved .
|The Material-Balance Equation “MBE” is a fundamental tool for
estimating the original gas-in-place “G” and predicting the recovery
performance of conventional gas reservoirs. For conventional gas
reservoirs, the MBE is expressed by the following linear equation:
|The material balance equation for the Coalbed methane can be
expressed in the following generalized form
|For Saturated Coalbed methane reservoir
|Gas originally adsorbed ‘G’
| with no water influx
|Original free gas GF
|Gas currently adsorbed GA
|It is expressed with the adsorption isotherm or mathematically by
|Remaining free gas GR
During the dewatering phase of the reservoir, formation
compaction (matrix shrinkage) and water expansion will significantly
affect water production. Some of the desorbed gas remains in the coalcleat
system and occupies a pore volume that will be available with
|Substituting all (1.2) to (1.7) in (1.1)
|General Material balance equation for Coalbed methane reservoirs:
|Neglecting compressibility we get
|Case study on Material balance equation
|The data was taken ANADARKO PETROLEUM CORP and shown
in Tables 1 and 2 and Figure 2.
|Best Cementing Practices of Coalbed Methane
|Cement is placed as a sheath across coal seams in Coalbed methane
wells primarily for hydraulic isolation and to support the casing.
Designing a cement job for coal seam wells requires contemplating
factors beyond those considered in cementing conventional oil and
gas wells. This topic deals with best practices developed in designing
the cement in Coalbed. These case histories include cement design
|Generally the Coalbed methane wells are drilled by air and removing
the cuttings before or during the cement jobs pose challenges. After
landing the casing at true depth, the cement job starts by circulating
water or spacer. The primary job of this spacer is to bring the cuttings
|Cement system design
|The cement designs vary according to the fracture gradient inside the well.
|i) Fracture gradient more than 0.7psi/ft
|A 14.5 ppg cement system with fluid loss control material will be effective and this category cement designs are least challenging and
objectives are achieved economically.
|ii) Fracture gradient between 0.65 psi/ft to 0.7psi/ft
|Designing suitable cement becomes challenging. If the fracture
gradient is near 0.65 psi/ft, the conventional 14.5-ppg cement induces
fractures and results in cement invasion in the cleat matrix with lost
circulation even when lost-circulation material is used. To overcome
these challenges, lightweight cement systems and mechanical aids were
used. The lightweight cement systems included hollow ceramic spheres,
which both reduced the density of the slurry and also helped to bridge
off the entrance of the cleats due to their particle size distribution.
|When the well’s fracture gradient approaches 0.68 psi/ft, 11.5-ppg
cement could be used successfully, but 12.5 ppg cement invaded the
cleats. However, the 11.5-ppg cement was found in most cases to have
inadequate compressive strength and poor bond with the casing as
shown in Figure 3. The 12.5-ppg cement had good bonding but entered
the cleat faces, and unexpected pressure rise was observed, indicated
fracturing was occurring by the cement system.
|iii) Fracture gradient of 0.6 to 0.65 psi/ft
|The third category, in which fracture gradient is between 0.60 and
0.65 psi/ft, requires a 10.5- to 11.0-ppg cement system. These systems
require almost 50% (by weight of cement lightweight materials and
hence impact the CBM economics substantially. These systems tend
to have lesser compressive strength, and the bond between the cement
and casing may not be as good as the other cases. These cement systems
also do not exhibit good tensile strength, which may adversely affect
hydro-fracturing operations. All the above cement systems also
require good fluid loss control to minimize the cement filtrate loss into
the cleat matrix, and zero free water.
|Spacer System Design
|As the Coalbed Methane wells are drilled using air, there is no
drilling mud used, and hence the cement spacer system does not have
to remove mud filter cake from the annulus or inside the casing. The
disadvantage is that formation cuttings and debris created during
running of the casing remain at the bottom of the well. When the
spacer is pumped, these materials start to float together and tend to
bridge off the annulus at any restricted area.
|A simple spacer can be designed for these wells using water with or
without surfactants. However, any cuttings or debris that is not lifted
by the spacer may be entrained in the cement and pack off the annulus
at restricted areas. Instead, a weighted spacer will lift the cuttings,
and the weight of the spacer can be designed so that the cuttings are
dispersed in the system during lifting, minimizing risks of bridging or
packing off the flow path.
|The volume of the spacer should be adequate to reach the float
equipment before cement pumping begins; this will ensure that the float equipment is not plugged off by debris/cuttings. This volume
could be the total of water and weighted spacer plus some extra 5 bbl
to ensure that the spacer passes the float equipment before the cement
|Case history No. 1
|The wells are located in the Raniganj block of West Bengal, East
India, where a 15-well drilling campaign was planned. Five production
casing cement jobs were pumped using a 11.5-ppg lightweight slurry
design. Static temperatures ranged from 130 to 143 deg F at depths
from 2297 to 3363 ft. Holes were vertically drilled with air (water &
foam mixture). Since lightweight, high strength slurries were used
rather than conventional cement, the CBL/VDL were expected to be
good, but they did not meet expectations (Figure 3). To improve the
CBL/VDL, a slurry designed at 12.5-ppg with the same lightweight
additive was pumped in two wells, achieving better CBL/VDL results
(Figure 4). Based on these results, the 12.5-ppg slurry was pumped in
six more wells. Meanwhile, the operating company started the well
completion campaign and started fracturing the wells where the 12.5-
ppg cement system was pumped. Stimulation was hindered difficulty
with perforating and then fracturing the wells, as the fracture initiation
pressures were abnormally high. The operator concluded that the
cement had invaded the cleat matrix.
|Case history No. 2
|A four-well campaign was about to start in the Barmer Sanchor
basin of Rajasthan, West India. The operating company was concerned
about the cement job because of the very soft formations, which could
lead to large openhole washouts. Engineers recommended pumping a
special type of a pre-flush called reactive pre-flush, which could clean
the washout sections better and prepare both casing and formation
for better cement bonding. The reactive pre-flush consisted of sodium
silicate and was pumped in the following order: 2% KCl solution –>2%
CaCl2 –>2% KCl solution –>Na2SiO3 solution –>2% KCl solution. The
2% KCl solution was included to prevent contact between CaCl2 and
Na2SiO2 as they can react to form solids if they mix. The pre-flush and
subsequent cementing operations were executed successfully.
|Coalbed methane production facilities: This describes the case
study on production facilities; ARCO has recently installed to develop
reserves on approximately fifty sections of land in the La Plata County,
Colorado area of the San Juan Basin for producing methane gas from
coal beds in the Cretaceous Fruitland formation. The project involves
107 wells and is expected to reach a peak rate of 85 MMCFD (2.4 E+06 m
3/dL The facilities described include artificial Lift, wellhead separation,
gathering systems, compression, gas treating, water disposal, field
automation and corrosion protection.
|The typical Fruitland producing well is a straight hole 3550' (1080
m) deep. The 8-5/8" (219 mm) surface casing is set at 500' (150 m) and
cemented to the surface to protect shallow water sands. The 5-1/2" (140
mm) production casing is set and cemented from TD to the surface.
After the production casing is set, approximately 50' (15 m) of the coal
interval is perforated and then fractured with 200,000 gallons (760
m3) of cross linked gel carrying 600,000 Ibs (272000 Kg) of sand. After
stimulation and cleanup, gas lift equipment is run on 2-7/8" (73 mm)
production tubing and a 3000 psi (20800 kPa) wellhead is installed.
|In order to maintain low bottom hole producing pressures
and because of the lack of electric power in the project area and the
expectation of coal fines in the produced water, only sucker rod pump
systems and the gas lift systems are an ideal choice. A significant
factor in this evaluation is the requirement to compress all gas to 550
psi (3900 kPa) for sales purposes. With the need for compression
equipment already justified by sales, the expansion to include volumes
for gas lift recycling was considerably less expensive than stand-alone
gas lift compression. Another significant factor in this selection was the
expected production rate.
|The limited range of individual pumping units was a negative to
the sucker rod system. The primary advantage of the sucker rod system
was it could possibly provide a 10 to 15% better bottomhole drawdown
than gas lift. Offsetting this advantage was the expectation of the pump
being plugged frequently due to coal fines. Frequent workovers were
anticipated to overcome this situation. The poor accessibility to well
sites six months of the year made the sucker rod option considerably
more expensive to operate than gas lift. Also, the difficulty in monitoring
flowing bottomhole pressures is seen as a negative. Because of these
factors gas lift was chosen as the means of artificial lift.
|Once when the water rate declines and if fines have stabilized
certain wells may be lifted with sucker rod pumps to achieve lower
bottom hole pressure. Likewise, some wells may ultimately be more
suited to intermittent gas lift, plunger lift or simply natural flow. In
order to meet the initial design production rates, the typical well
requires 200 MCFD (5700 m3/d) of 600 psi (4230 kPa) gas at the casing
head to maintain less than a 250 psig (1830 kPa) bottomhole pressure.
For kick off purposes, 700 psig (4930 kPa) gas is required. Two to three
wireline retrievable pressure operated kickoff valves with 5/64 inch
orifice (0.20 cm) are installed in side pocket mandrels to unload the
well. The operating valve is an orifice type sized between 10/64 to 15/64
inch (4 to 6 mm).
|Typical Well Site Equipment of a Coalbed Methane
|Each well site is equipped with a production separator, a water
handling system and a meter skid figure below illustrates the typical
well site process flow diagram (Figure 5).
|Curves for coalbed methane production prediction
|Gas production from CBM reservoirs is governed by complex
interaction of single-phase gas diffusion through micro-pore system
(primary porosity) and two-phase gas and water flow through cleat
system (secondary porosity) that are coupled through desorption
process. In order to effectively evaluate CBM resources, it’s necessary
to utilize reservoir models that incorporate the unique flow and storage characteristics of CBM reservoirs [3,4] (Figure 6).
|Reservoir model description
|A two-dimensional Cartesian (CBM base) model is developed for
an under-saturated CBM reservoir with a well located at the center of the drainage area shale gas reservoirs. GEM includes options for gas
sorption in the matrix, gas diffusion through. The reservoir simulation
software used in this study was GEM4. GEM is CMGs advanced general
equation of state, compositional, dual porosity reservoir simulator.
Capable of modeling both coal and the matrix, two phase flow through
the natural fracture system. The reservoir parameters used to develop
the base model are summarized in Table 1. A set of published relative
permeability5 was used in the model. The simulation runs were made
by varying several of the key parameters over the ranges provided in
|Type curve development
|In order to develop type curves, two set of dimensionless rate and
time were defined for gas and water. The gas dimensionless terms are
|these definitions are based on those used for gas production adjustment.
|Similarly water dimesionless rate and time were defined
|The base model is then converted to dimensionless rate and time
using above definitions and results were plotted as shown in Figures
7 and 8.
|In order to establish the uniqueness of this curves the impact of the
key reservoir parameters were investigated. Below figure illustrates the
gas type curves generated for various flowing bottomhole pressures.
The impact of flowing bottomhole pressure on water type curve, in the
range considered from 50psia to 100psia is negligible (Figure 9).
|Relative permeability characteristic have significant impact on gas
and water production from a coal reservoir because of the two phase
flow condition particularly at early stages of production (Figures 10
|Use of Reservoir Simulation for Diagnosing Causes of
|The diagnosis of reservoir, near-wellbore, and wellbore conditions
that impair production is enhanced with the use of reservoir simulation.
In the case of modeling CBM wells, a simulator used for such purpose
must be able to model the physics of Coalbed methane desorption and
diffusion flow through the coal matrix. It must also be able to calculate
original-gas-in-place using the Langmuir isotherm. In constructing a
single-well model for a well, the known data we normally have are coal
thickness, coal density, produced gas composition and initial reservoir
pressure, from which initial gas content values and OGIP per acre are
determined. Production history data include daily gas and water rates
and wellhead flowing pressures. Where we have a nearby pressure
monitoring well, we also have a record of the reservoir pressure history
at the monitoring well’s location. We use the model in history match
mode to solve for drainage area, initial permeability, the pressuredependent
permeability function (PdP), and the initial cleat porosity
and water saturation. In conjunction with the simulator solution, we
use the Production Data Analysis (PDA) method [5,6]. This method
uses production rate, reservoir pressure and flowing pressure data to
solve for the effective permeability to gas (Kg) as a function of reservoir
pressure using the pseudosteady-state radial flow equation from
|Using equation (3), we construct a plot of kg versus reservoir
pressure, from which the pressure-dependent permeability function
(PdP) function to be used in the simulator is determined. The PDA
method assumes that reservoir pressure, drainage area, skin and
thickness are known or may be independently obtained (and that the
Dqg term is a constant). Because drainage area and therefore OGIP and
reservoir pressure, as a function of cumulative production, are usually
not known before modeling a well, the PDA analysis must be done
in iteration with the reservoir simulator to arrive at a final reservoir
characterization that satisfies all the data. A plot of kg versus reservoir
pressure for San Juan Fairway wells, Well001 is shown in Figure 12.
|Figure 12 shows an increasing permeability trend as a function of
declining reservoir pressure from the initial reservoir pressure of 1466
psi down to 320 psi. The kg values calculated below 320 psi show an
opposite, downward trend in permeability. We therefore calculated the pressure-dependent permeability (PdP) function in two parts for use
in the model. The increasing segment, from initial reservoir pressure
of 1466 psi down to 320 psi, was matched using the Palmer-Mansoori
equation . The segment below 320 psi was matched using a linear
line fit to the kg data extrapolated to a value of 15 md at 0 psi reservoir
pressure. The overall PdP function that we used to achieve the history
match is depicted by the red line in Figure 12. Based on the history
match, we estimate that the initial permeability was 7.5 md, that it
peaked in 1997 at 117 md, and that it has declined from its peak to
a current 54 md. Once the history match is achieved, it is possible to
use the simulator to calculate the theoretical maximum reservoir flow
capacity. We do this by running the model on flowing bottomhole
pressure control and using a minimum flowing bottomhole pressure
such as 25 psia. The curve representing the theoretical maximum flow
is then plotted on the production history chart and compared to actual
production. This is depicted in figure shown below in Figure 13.
|We then compare actual production rates with the theoretical
maximum production rate determined by the simulator and investigate
causes for where they differ. In the case of Well001 prior to 1999, the
well had high water rates and consequently high flowing bottom hole
pressures (FBHPs), which is why it did not produce up to its maximum
capacity in these early years. When the well de-watered and a low
FBHP was achieved in 1999, gas production was close to the theoretical
maximum for about four years. Then, beginning in 2003, gas rates
started to fall below the theoretical maximum despite low FBHPs.
This loss in production efficiency was caused by coal fines and paraffin
plugging of the near-wellbore region, creating a progressively greater
skin. The well began to experience significant production losses in
2006, when the first of four cleanout operations was conducted. These
cleanouts were directed at cleaning out fill and removing paraffin from
inside the liner. Following each cleanout, the well’s gas rates improved
significantly but not quite up to the theoretical maximum. This is
because the cleanouts were unable to significantly reduce the wellbore
|Development of gas reservoirs contained within the Coalbed requires no new technology in terms of surface facilities. Coalbed
reservoirs need low flowing tubing head pressures to maximize
|➢ The MBE can provide an independent source of validation
for numerical simulators.
|➢ The MBE method eliminates the iterative solution of king’s
|➢ This material balance equation is applicable to any coal
which behaves according to the Langmuir isotherm equation.
|➢ Cement designs for Coalbed methane require additional
considerations compared to conventional oil and gas well cementing
because of Coalbed methane economics, fracture gradient, cement
invasion in cleats, cement strengths, fluid loss control and use of lost
|➢ Study of the Coalbed methane cleat system is critical for
proper cement design.
|➢ Reducing slurry density is useful if the fracture gradient
is low, but the cement must still have good compressive and tensile
|➢ Large diameter piping vessels combined with substantial
amount of compression is required to bring the gas to marketable
|Gp=cumulative gas produced, SCF
|G=gas originally adsorbed, SCF
|GF=original free gas, SCF
|GA=gas currently adsorbed, SCF
|GR=remaining free, SCF
|A=drainage area, acres
|ρB= bulk density of coal, gm/cm3
|Gc= gas content, SCF/ton
|h= average thickness, ft
|Swi= Initial water saturation
|Egi= Gas expansion factor at Pi, SCF/BBl
|V=Volume of the gas currently adsorbed at P, SCF/ton
|Vm=Langmuir isotherm constant, SCF/TON
|b=Langmuir pressure constant, psi-1
|p= Pressure, psi
|Pi=Initial pressure, psi
|Wp=Cumulative water produced, STB
|Bw= Water formation volume factor bbl/STB
|Cw= Isothermal compressibility of the water, psi-1
|Cf=Isothermal compressibility of the water, psi-1
|D=inertial or turbulent flow factor, D/Mscf
|h=formation thickness, ft
| kg=effective permeability to gas, md
|pR=volumteric average reservoir pressure, psia
|pwf=flowing bottomhole pressure, psia
|qg=gas surface flow rate, Mscf/D
|re=drainage radius, ft
|rw=wellbore radius, ft
|s=skin factor, dimensionless
|(qpeak)g=maximum peak rate
|Gi=initial gas in place
|Gc= gas content of the coal SCF/ton
|ρc=coal bulk density
|qiw= initial maximum water rate
|Wi=initial water in the cleat system
|ØF=cleat system porosity
- Ahmed T, Centilmen A, Roux B (2006) A Generalized Material Balance Equation for Coalbed Methane ReservoirsSPE Annual Technical Conference, San Antonio, Texas USA.
- Mohammad HSG, Shaikh S(2010) Coalbed Methane Cementing Best Practices-Indian Case History, CPS/SPE International Oil & Gas Conference, Beijing, China.
- Okotie VU, Moore RL(2010) Well Production Challenges and Solutions in a Mature, Very Low Pressure Coalbed Methane Reservoir,Canadian & International Petroleum Conference, Calgary, Alberta Canada.
- Aminian K, Ameri S, Bhavsar A, Sanchez M, Garcia A (2004) Type Curves for Coalbed Methane Production Prediction, SPE Eastern Regional Meeting, Charleston, West Virginia.
- D W Moore (1990)Coalbed methane production facilities a Case history, SPE 65th Annual Technical Conference & Exhibition, New Orleans, LA.
- Ahmed T, Meehan N (2011) Advanced Reservoir Management and Engineering. [2ndEdn] Gulf professional Publishing, USA.
- Palmer I, Mansoori J (1998) How Permeability Depends on Stress and Pore Pressure in Coalbeds: A New Model paper SPE 52607, SPEREE 539-544.