Global Production Practices - CBM

“GLOBAL CBM PRODUCTION PRACTICES”

Production Practice of CBM

Introduction Seismic drilling Logging Well completion Enhanced CBM Recovery Techniques Production Uses Conclusion

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What Is CBM?

Coal Bed Methane is naturally occurring methane (CH4) with small amounts of other hydrocarbon and non-hydrocarbon gases contained in coal seams as a result of chemical and physical processes. It is often produced at shallow depths through a bore-hole that allows gas and large volumes of water with variable quality to be produced. CBM resources represent valuable volumes of natural gas within and outside of areas of conventional oil & gas production. Many coal mining areas currently support CBM production; other areas containing coal resources are expected to produce significant volumes of natural gas in the near future.

CBM is intimately associated with coal seams that represent both the source and reservoir. Coals have an immense amount of surface area and can hold enormous quantities of methane. Since coal seams have large internal surfaces, they can store on the order of six to seven times more gas than the equivalent volume of rock in a conventional gas reservoir. CBM exists in the coal in three basic states: as free gas; as gas dissolved in the water in coal; and as gas “adsorbed” on the solid surface of the coal.

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Overview of CBM

• CBM is an environmentalFriendly clean fuel withproperties similar to naturalGas.

• Coal serves as both sources aswell as the reservoir rock forCBM. • CBM is generated within thecoal seams during ‘coalification’Process and remains adsorbedIn the internal surface of coalMatrix.

• Relatively simpleWells

• Access to multiplecoal seams through asingle well

• Expected life ofAround 15 years

•Low pressureGathering systems

•Small footprint.

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•Methane gas adsorbed intocoal seams that can hold 5times as much gas as anequivalent volume ofsandstone

• Gas held in coals byhydrostatic water pressure

• Pumping water lowers thehydrostatic pressure and gasdesorbs from the coals incleats and fractures to flow tosurface

How is CBM Produced?

CBM wells are completed in several ways, depending upon the type of coal in the basin and fluid content. Each type of coal (sub-bituminous to bituminous) offers production options that are different due to the inherent natural fracturing and competency of the coal seams. The sub-bituminous coals are softer and less competent than the higher rank low-volatile bituminous coals, and therefore are typically completed and produced using more conventional vertical well bores. The more competent higher rank coals lend themselves to completions using horizontal as well as vertical well bores.

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Figure provides a typical well completion for CBM. The well is drilled to the top of the

target coal seam and production casing is set and cemented back to surface.

The coal seam is then drilled-out and under reamed to open up more coal face to production. The borehole and coal face are then cleaned with a slug of formation water pumped at a high rate (water-flush).

In areas where the cleat or natural fracture system is not fully developed, the coal may be artificially fractured using a low-pressure water fracture treatment. These shallow wells are typically drilled with a small mobile rig mounted on a truck.

Once the well is completed, a submersible pump is run into the well on production tubing to pump the water from the coal seam. By removing the water from the coal seam the formation water pressure is reduced and the methane is desorbed (released) from the coal, thus initiating production.

Typical figure of a CBM wellThe methane flows up both the casing and tubing of the well and is sent via pipe to a

gas/water separator at the compression station.The methane is then compressed for shipment to the sales pipeline. Attempts at

producing more than one coal seam per well have been mostly unsuccessful due to the inherent problem of lowering the water level in each coal seam independent of each other.

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Size constraints of the production equipment and use of submersible pumps make the

use of dual completion complicated and expensive. With CBM production wells typically being so shallow, it is less expensive and less complicated to drill wells into each coal seam independently than to use dual or triple completion well systems. As water is pumped off the coal aquifer, increasing amounts of methane are produced from the CBM wells.

What Controls CBM Production?

CBM production potential is a product of several factors that vary from basin to basin – fracture permeability, development, gas migration, coal maturation, coal distribution, geologic structure, CBM completion options, hydrostatic pressure and produced water management. In most areas, naturally developed fracture networks are the most sought after areas for CBM development. Areas where geologic structures and localized faulting have occurred tend to induce natural fracturing, which increases the production pathways within the coal seam. This natural fracturing reduces the cost of bringing the producing wells on line. Most coals contain methane, but it cannot be economically produced without open fractures present to provide the pathways for the desorbed gas to migrate to the well. As long as the pressure exerted by the water table is greater than that of the coal the methane remains trapped in the coal bed matrix. Coal cleats and fractures are usually saturated with water, and therefore the hydrostatic pressure in the coal seam must be lowered before the gas will migrate.

Lowering the hydrostatic pressure in the coal seam accelerates the desorption process. CBM wells initially produce water primarily; gas production eventually increases, and as it does water production declines. Some wells do not produce any water and begin producing gas immediately, depending on the nature of the fracture system. Once the gas is released, it is usually free of any impurities; is of sufficient quality and can be easily prepared for pipeline delivery. Some coals may never produce methane if the hydrostatic pressure cannot be efficiently lowered. Some coal seams may produce gas, but are too deep to economically drill. CBM wells are typically no more than 5000’ in depth, although some deeper wells have been drilled.

Fundamentals of CBM

Permeability of coal bed methane reservoirPermeability 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. 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

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and end at face cleats. Hence, on a small scale, fluid flow through coal bed methane reservoirs usually follows 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.

Porosity

Porosity of coal bed reservoirs is usually very small ranging from 0.1 to 10%. Coal seams are characterized by two distinctive porosity systems: a well-defined and almost uniformly distributed network of natural fractures (cleats), and a coal matrix containing a highly heterogeneous porous structure between the cleats. Cleats account for less than 2 percent of the seam bulk volume. Therefore, storage of free gas in the pore spaces of coal cleats represents a minor part of the total gas-in-place. However, the cleat porosity system is very important in coal bed reservoirs because nearly all the reservoir permeability comes from presence of cleats network in the coal seams. The coal matrix contains very fine pore spaces. These pores are referred to as micro pores. It has been reported that coal micro pores can be as small as a few nanometers in diameter. Micro pores do not contribute significantly to permeability, but they are excellent sites for gas storage in adsorbed form. Because of coal micro pores, it is estimated that a gram of coal may contain up to 200 square meters of internal surface for methane adsorption. Micro pores are commonly referred to as the coal primary porosity system whereas cleats are referred to as coal secondary porosity system caused by geological processes such as structural deformation, differential compaction and volume contraction.

Adsorption capacity

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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 are drained first. This leads to a reduction of pressure enhancing desorption of gas from the matrix.

Fracture permeabilityAs 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.

Relative Permeability in coal bed reservoir

Relative permeability is a primary parameter in determining coal bed reservoir production characteristics. Gas and water flow in cleats are mainly controlled by relative permeability. Therefore, an appropriate estimation of relative permeability characteristics of the coal seam is needed to understand the reservoir performance properly.

Thickness of formation and initial reservoir pressure

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The thickness of the formation may not be directly proportional to the volume of gas

produced in some areas. Some coal and or shale formations may have higher gas concentrations regardless of formation thickness. This is likely case specific depending on 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.

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KEY ADVANCES IN COALBED METHANE TECHNOLOGY

The coal bed methane research has produced three key technological advances in reservoir engineering:

An Improved Understanding of the Fundamentals of Coal bed Methane Production Advances in Measuring Reservoir Properties Advances in Reservoir Simulation

Understanding the Fundamentals of Coal bed Methane Productioninitially, research focused on understanding the fundamental differences between coal bed methane and conventional reservoirs. Later work centered on developing tools for predicting coal bed methane production. The understanding of coal bed methane has advanced so that reservoir engineers can evaluate new properties and manage production from existing wells over the long term. To successfully produce coal bed methane wells, it is essential to:

1) Identify factors that control production in coal reservoirs,

2) Understand the relationship between gas content and sorption isotherm for specific developments, and

3) Maintain low backpressure on wells to increase recovery. Each of these points is discussed below.

Factors that Control Production in Coal Reservoirs. Early work showed that gas is stored in an adsorbed state on coal, and thus for a given reservoir pressure much more gas can be stored in a coal seam than in a comparable sandstone reservoir. Production of gas is controlled by a three step process & desorption of gas from the coal matrix, diffusion to the cleat system, and flow through fractures. Many coal reservoirs are water saturated, and water provides the reservoir pressure that holds gas in the adsorbed state.

Relationship Between Gas Content and Sorption Isotherm. Another mechanism that controls production is the relationship of gas content to sorption isotherm. The sorption isotherm defines the relationship of pressure to the capacity of a given coal to hold gas at a constant temperature. Gas content is a measurement of the actual gas contained in a given coal reservoir. A coal reservoir is undersaturated if the actual gas content is less than the isotherm value at reservoir temperature and pressure. Accurate measurements of both gas content and the isotherm are required to estimate the production profile of the well.

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Maintaining Low Backpressure on Wells. The ultimate recovery of gas depends on gas content and reservoir pressure. Gas production will not initiate until reservoir pressure falls below the point where the gas content of the coal is in equilibrium with the isotherm. Because most coal reservoirs are aquifers, production of water from the wellbore is the primary mechanism of pressure reduction. If the gas content of the reservoir is below the isotherm, then the reservoir will produce only water initially. After this single phase flow period, bubble flow initiates when reservoir pressure reaches the saturation point on the isotherm. Eventually, two phase flow of gas and water occurs as pressure is further reduced in the reservoir. Because of the relationship between gas desorption and reservoir pressure, it is important to produce coal bed methane wells at the lowest practical pressure.

Advances in Measuring Reservoir Properties. In 1982, few references were available on testing coal bed methane wells. Today, the results of extensive field research has greatly advanced the understanding and application of coal bed methane well testing. Much of the knowledge used to perform and interpret coal bed methane well tests has been modified from well testing technology used in the oil and gas industry. Research on coal bed methane well testing has produced several useful findings:

Coal permeability is very sensitive to stress conditions. When performing injection/falloff tests on coal seams it is important to inject at very low rates to avoid fracturing the coal and to minimize stress effects.

High skin factors often are encountered when testing coal seams, especially when testing a cemented and cased well. The high skin factor indicates poor communication between the well bore and the natural fracture system in the reservoir and makes it more difficult to determine permeability accurately. The high skin factor often can be eliminated by performing a breakdown treatment or small stimulation before testing.

Absolute permeability of coal natural fracture systems can be estimated from well tests performed under multiphase flow conditions if accurate relative permeability curves are available.

Because of the highly heterogeneous nature of coal reservoirs, well tests with short radii of investigation may not yield representative permeability values.

A new well testing procedure, the Tank Test, was developed. This test utilizes gravity drainage to inject water into under-pressured reservoirs. The Tank Test can be performed for less cost than an injection/falloff test. It also prevents fracturing of the coal during injection and minimizes stress effects.

In the over-pressured portions of the western coal basins, drill stem testing is an effective method for determining permeability.

A Zone Isolation Packer (ZIPTM) can be used to measure production from individual zones in multi-seam wells.

A wide variety of tests can be used to evaluate coal bed methane wells. These include production or injection drill stem tests, cased-hole production and injection tests, slug tests, tank tests, and tests combined with production logging. Selecting the test type depends primarily on the completion type of the well, the level of natural fracture system development, the average pressure of the natural fracture system, and the reservoir saturation conditions. Economic factors will also influence test selection. The least expensive tests are water production or injection slug tests of higher permeability under-pressured reservoirs.

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Designing coal bed methane well tests requires estimates of the ranges of reservoir permeability and pressure. When testing wildcat wells in unknown areas, standard test procedures must be used and modified because permeability estimates are not available before testing. Measuring permeability from well tests can be difficult because two-phase flow of gas and water usually occurs during production. Most early coal bed methane well testing research was based on single-phase flow and standard hydrologic tests. Recently, significant advances have been made in performing and interpreting two-phase well tests for naturally fractured coal reservoirs. However, current technology in both single- and multiphase- flow can provide accurate estimates of permeability if tests are properly designed and interpreted.

Today, most coal bed methane well test interpretation is based on using diagnostic graphs and history matching measured pressure behavior. Though coal bed methane reservoirs are dual porosity systems, dual porosity models are not required to interpret well test behavior. Using single porosity models simplifies the analysis procedures. Commercially available well test analysis software can be used for interpreting coal bed methane reservoir tests by accounting for multiphase flow and including gas readsorption in the total compressibility factor. Other approaches, such as new type curves for two-phase flow conditions, are also being developed.

Despite the large number of coal bed methane wells on production, few well tests are routinely performed. It is important to understand, however, that by using current coal bed methane well testing technology, producers can obtain accurate, cost-effective estimates of permeability for

evaluating existing properties and new prospects in emerging coal basins. Continued advances in interpreting multiphase flow well tests are likely in the future. These advances will be enhanced by the increased emphasis on reservoir characterization, data integration, and

computer technology

Seismic Study and Data Acquisition

In order to optimally design the 3C-3D survey used for time-lapse imaging of the pilot, 3-component vertical seismic profiles were obtained in the test well using three different sources. Zero-offset VSPs were shot using compressional and shear sources, and two compressional sources were used for walkaway surveys. Surface seismic data was also obtained using single-component geophones during the recording of the VSPs. The top of the Ardley coal zone at the site is at approximately 290 m KB. The geometry of the survey is illustrated in Figure 1.

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Figure 1: Geometry of the seismic acquired at Red Deer. A walk away 3-component vertical seismic profile was recorded in addition to a zero-offset 3-component VSP and single-component surface seismic. Image is not to scale.

The first source tested for the zero-offset survey was a 44,000 lb. P-wave Vibroseis truck (“big-P”), using a sweep of 8-150 Hz. A smaller mini P-wave truck-mounted Vibroseis unit was also tested, using an 8-250 Hz sweep, as well as a mini shear-wave truck-mounted Vibroseis, sweeping 8-150 Hz (referred to as “mini-P” and “mini-S”, respectively. Three-component receivers were spaced at 5 m intervals from TD (300 m) to surface within the wellbore, and all recording was undertaken at a 1 ms sampling rate. Surface receivers were planted at 10 m intervals.

Results

Frequency spectrum analysis of the big-P VSP data indicates a useable bandwidth of 15-150 Hz. Upper and lower contacts for the 9 m thick Ardle coal zone are clearly resolved on the big-P VSP data with high amplitude reflections from the coal zone (Figure 2).

Figure 2: Corridor stack of vertical component of big-P zero offset VSP data from Red Deer test well #1, correlated with synthetic seismograms. Seismogram on the left is produced

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by convolution with the extracted down going wavelet, whereas the central seismogram is convolved with a 90 Hz Ricker wavelet. An intra-coal event is visible on the first seismogram, but not on the corridor stack, in which the top and base of the Ardley coal zone both produce strong amplitude reflections.

Higher bandwidths of 15-220 Hz were recorded on the mini-P data set. Examining the VSP data clearly shows an event within the coal zone (Figure 3). This reflection may represent shale parting or a tight calcite streak within the coal, although log data shows the largest impedance contrasts bound a layer within the coal zone that is only 0.5 m thick. The high bandwidth recorded suggests that strong impedance contrasts within a coal zone may allow detailed mapping of individual seams within a coal zone, or locating undesirable tight streaks prior to CBM development.

Figure 3: Corridor stack of vertical component of mini-P zero offset VSP from the field test site, correlated with synthetic seismograms. The leftmost seismogram is convolved with a 100 Hz Ricker wavelet, whereas the center seismogram is convolved with the extracted down going wavelet. On the corridor stack, the top and base of the Ardley coal both produce strong amplitude reflections, and a secondary event within the coal zone is also visible.

Upper and lower coal contacts both produce strong amplitude reflections recorded on the horizontal component of the mini-S VSP data. In the compressional-wave data sets, the seismic response of the upper contact of the coal is the maximum of a peak. There appears to be a slight phase difference between the P and S data sets (Figure 4). Zero-offset mini-S data has slightly higher resolution than big-P data, and has a usable bandwidth of 15-80 Hz, which is quite high for shear-wave data. However, the coal is relatively shallow, and little attenuation has occurred relative to deeper data sets normally examined. Deffenbaugh et al. (2000) noted similar high resolutions in the shallow section in an examination of the resolution of converted waves.

A comparison of corridor stacks from each source is illustrated in figure 5

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Figure 4: Corridor stack of horizontal component of mini-S zero offset VSP, correlated with a synthetic seismogram (middle) and the corridor stack for the big-P data. The top and base of the Ardley coal both produce strong reflections on the S-wave data, although the upper contact is imaged as a point of inflection rather than as a peak maximum, as in the compressional VSP data. Two-way times have been converted to p-wave time for ease of comparison of the data sets.

Figure 5: Comparison of corridor stacks for the big-P, mini-P, and mini-S sources. A slight phase rotation is noted in the shear data compared to the compressional data. All plots are in p-wave time for ease of comparison.

The use of different sources allows a detailed examination of the Vp/Vs character of the shallow strata (Figure 6). Examination of the first arrival times for each source demonstrates high average Vp/Vs (greater than 3.0) in the shallowest strata down to 100 m depth, decreasing to average Vp/Vs of 2.5 at 300 m.

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Figure 6: Depth vs. average Vp/Vs for Red Deer test well indicates high Vp/Vs values in the shallow section above 100 m depth, and gradually decreasing ratios from 100 m to 300 m.

Surface seismic data at the test site recorded a high amplitude reflection from the coal zone. Stacked data from the test site is very low fold, but the coal reflection is clearly visible on a filtered shot record (Figure 7). A full-fold 3D survey is expected to successfully map lateral facies and thickness changes of the coal zone across the survey area. Repeated surveys over the course of enhanced coal bed methane production will likely image changes in the coal response resulting from dewatering and gas injection (Richardson et al., 2002). These changes in response should be indicative of the accompanying physical changes in reservoir properties.

Seismic data collected during this first phase of the pilot project allows for detailed numerical and physical modeling of the test site, thus allowing optimal design of time-lapse surveys to be completed in later phases.

Figure 7: Filtered shot record of surface data collected at the test site – channel spacing is 10 m with a corner at channel 22, marked by green arrow, vertical scale is in ms. A red arrow highlights the coal response.

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A full seismic monitoring program of ECBM production will include full well-log suites such that detailed physical properties of coal seams may be determined throughout the survey area. Repeated VSP surveys will provide detailed seismic studies of the area surrounding the borehole, and cross well seismic surveys will allow greater examination of the coal seam in particular.

2 Drilling Technology

There are many types and designs of drilling rigs, with many drilling rigs capable of switching or combining different drilling technologies as needed. Drilling rigs can be described using any of the following attributes:

By power used mechanical - the rig uses torque converters, clutches, and transmissions powered by its

own engines, often diesel electric - the major items of machinery are driven by electric motors, usually with power

generated on-site using internal combustion engines hydraulic - the rig primarily uses hydraulic power pneumatic - the rig is primarily powered by pressurized air steam - the rig uses steam-powered engines and pumps (obsolescent after middle of

20th Century)

By pipe used cable - a cable is used to raise and drop the drill bit conventional - uses metal or plastic drill pipe of varying types coil tubing - uses a giant coil of tube and a down hole drilling motor

By height single - can drill only single drill pipes, has no vertical pipe racks (most small drilling

rigs) Double - can hold a stand of pipe in the derrick consisting of two connected drill pipes,

called a "double stand". Triple - can hold a stand of pipe in the derrick consisting of three connected drill pipes,

called a "triple stand".

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By method of rotation or drilling method no rotation includes direct push rigs and most service rigs Rotary table - rotation is achieved by turning a square or hexagonal pipe (the Kelly) at

drill floor level. Top-drive - rotation and circulation is done at the top of the drill string, on a motor that

moves in a track along the derrick. sonic - uses primarily vibratory energy to advance the drill string

By position of derrick conventional - derrick is vertical slant - derrick is slanted at a 45 degree angle to facilitate horizontal drilling Drill types

There are a variety of drill mechanisms which can be used to sink a borehole into the ground. Each has its advantages and disadvantages, in terms of the depth to which it can drill, the type of sample returned, the costs involved and penetration rates achieved. There are two basic types of drills: drills which produce rock chips, and drills which produce core samples.

Auger drilling

Auger drilling is done with a helical screw which is driven into the ground with rotation; the earth is lifted up the borehole by the blade of the screw. Hollow stem Auger drilling is used for environmental drilling, geotechnical drilling, soil engineering and geochemistry reconnaissance work in exploration for mineral deposits. Solid flight augers/bucket augers are used in construction drilling. In some cases, mine shafts are dug with auger drills. Small augers can be mounted on the back of a utility truck, with large augers used for sinking piles for bridge foundations.

Auger drilling is restricted to generally soft unconsolidated material or weak weathered rock. It is cheap and fast.

Cable tool water well drilling

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Percussion rotary air blast drilling (RAB)

RAB drilling is used most frequently in the mineral exploration industry. The drill uses a pneumatic reciprocating piston-driven 'hammer' to energetically drive a heavy drill bit into the rock. The drill bit is hollow, solid steel and has ~20 mm thick tungsten rods protruding from the steel matrix as 'buttons'. The tungsten buttons are the cutting face of the bit.

The cuttings are blown up the outside of the rods and collected at surface. Air or a combination of air and foam lift the cuttings.

RAB drilling is used primarily for mineral exploration; water bore drilling and blast-hole drilling in mines, as well as for other applications such as engineering, etc. RAB produces lower quality samples because the cuttings are blown up the outside of the rods and can be contaminated from contact with other rocks. RAB drilling rarely achieves more than 150 meters depth as encountering water rapidly clogs the outside of the hole with debris, precluding removal of drill cuttings from the hole.

This can be counteracted, however, with the use of 'stabilizers' also known as 'reamers', which are large cylindrical pieces of steel attached to the drill string, and made to perfectly fit the size of the hole being drilled. These have sets of rollers on the side, usually with tungsten buttons, that constantly break down cuttings being pushed upwards.

The use of multiple high-powered air compressors, which push 900-1150cfm of air at 300-350psi down the hole also ensures drilling of a deeper hole up to ~1250m due to higher air pressure which pushes all rock cuttings and any water to the surface. This, of course, is all dependent on the density and weight of the rock being drilled, and on how worn the drill bit is.

Air core drilling

Air core drilling and related methods use hardened steel or tungsten blades to bore a hole into unconsolidated ground. The drill bit has three blades arranged around the bit head, which cut the unconsolidated ground. The rods are hollow and contain an inner tube which sits inside the hollow outer rod barrel. The drill cuttings are removed by injection of compressed air into the hole via the annular area between the inner tube and the drill rod. The cuttings are then blown back to surface up the inner tube where they pass through the sample separating system and are collected if needed. Drilling continues with the addition of rods to the top of the drill string. Air core drilling can occasionally produce small chunks of cored rock.

This method of drilling is used to drill the weathered regolith, as the drill rig and steel or tungsten blades cannot penetrate fresh rock. Where possible, air core drilling is preferred over RAB drilling as it provides a more representative sample. Air core drilling can achieve depths approaching 300 meters in good conditions. As the cuttings are removed inside the rods and are less prone to contamination compared to conventional drilling where the cuttings pass to the surface via outside return between the outside of the drill rob and the walls of the hole. This method is more costly and slower than RAB.

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Cable tool drilling

Speed Star Cable Tool Drilling Rig, Ballston Spa, NY

Cable tool rigs are a traditional way of drilling water wells internationally and in the United States. The majority of large diameter water supply wells, especially deep wells completed in bedrock aquifers, were completed using this drilling method. Although this drilling method has largely been supplanted in recent years by other, faster drilling techniques, it is still the most practicable drilling method for large diameter, deep bedrock wells, and in widespread use for small rural water supply wells. The impact of the drill bit fractures the rock and in many shale rock situations increases the water flow into a well over rotary.

Also known as ballistic well drilling and sometimes called "spudders", these rigs raise and drop a drill string with a heavy carbide tipped drilling bit that chisels through the rock by finely pulverizing the subsurface materials. The drill string is comprised of the upper drill rods, a set of "jars" (inter-locking "sliders" that help transmit additional energy to the drill bit and assist in removing the bit if it is stuck) and the drill bit. During the drilling process, the drill string is periodically removed from the borehole and a bailer is lowered to collect the drill cuttings (rock fragments, soil, etc.). The bailer is a bucket-like tool with a trapdoor in the base. If the borehole is dry, water is added so that the drill cuttings will flow into the bailer. When lifted, the bailer closes and the cuttings are then raised and removed. Since the drill string must be raised and lowered to advance the boring, casing (larger diameter outer piping) is typically used to hold back upper soil materials and stabilize the borehole.

Cable tool rigs are simpler and cheaper than similarly sized rotary rigs, although loud and very slow to operate. The world record cable tool well was drilled in New York to a depth of almost 12,000 feet. The common Bucyrus Erie 22 can drill down to about 1,100 feet. Since cable tool drilling does not use air to eject the drilling chips like a rotary, instead using a cable strung bailer, technically there is no limitation on depth.

Reverse circulation (RC) drilling

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Reverse Circulation (RC) rig, outside Newman,

Track mounted Reverse Circulation rig (side view).

RC drilling is similar to air core drilling, in that the drill cuttings are returned to surface inside the rods. The drilling mechanism is a pneumatic reciprocating piston known as a hammer driving a tungsten-steel drill bit. RC drilling utilizes much larger rigs and machinery and depths of up to 500 meters are routinely achieved. RC drilling ideally produces dry rock chips, as large air compressors dry the rock out ahead of the advancing drill bit. RC drilling is slower and costlier but achieves better penetration than RAB or air core drilling; it is cheaper than diamond coring and is thus preferred for most mineral exploration work.

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Reverse circulation is achieved by blowing air down the rods, the differential pressure creating air lift of the water and cuttings up the inner tube which is inside each rod. It reaches the bell at the top of the hole, then moves through a sample hose which is attached to the top of the cyclone. The drill cuttings travel around the inside of the cyclone until they fall through an opening at the bottom and are collected in a sample bag.

The most commonly used RC drill bits are 5-8 inches (12.7–20.32 cm) in diameter and have round metal 'buttons' that protrude from the bit, which are required to drill through rock and shale. As the buttons wear down, drilling becomes slower and the rod string can potentially become bogged in the hole. This is a problem as trying to recover the rods may take hours and in some cases weeks. The rods and drill bits themselves are very expensive, often resulting in great cost to drilling companies when equipment is lost down the bore hole. Most companies will regularly 'sharpen' the buttons on their drill bits in order to prevent this, and to speed up progress. Usually, when something is lost (breaks off) in the hole, it is not the drill string, but rather from the bit, hammer, or stabilizer to the bottom of the drill string (bit). This is usually caused by a blunt bit getting stuck in fresh rock, over-stressed metal, or a fresh drill bit getting stuck in a part of the hole that is too small, due to having used a bit that has worn to smaller than the desired hole diameter.

Although RC drilling is air-powered, water is also used, to reduce dust, keep the drill bit cool, and assist in pushing cutting back upwards, but also when collaring a new hole. A mud called liqui-pol is mixed with water and pumped into the rod string, down the hole. This helps to bring up the sample to the surface by making the sand stick together. Occasionally, 'super-foam' (AKA 'quick-foam') is also used, to bring all the very fine cuttings to the surface, and to clean the hole. When the drill reaches hard rock, a collar is put down the hole around the rods which is normally PVC piping. Occasionally the collar may be made from metal casing. Collaring a hole is needed to stop the walls from caving in and bogging the rod string at the top of the hole. Collars may be up to 60 meters deep, depending on the ground, although if drilling through hard rock a collar may not be necessary.

Reverse circulation rig setups usually consist of a support vehicle, an auxiliary vehicle, as well as the rig itself. The support vehicle, normally a truck, holds diesel and water tanks for resupplying the rig. It also holds other supplies needed for maintenance on the rig. The auxiliary is a vehicle, carrying an auxiliary engine and a booster engine. These engines are connected to the rig by high pressure air hoses. Although RC rigs have their own booster and compressor to generate air pressure, extra power is needed which usually isn't supplied by the rig due to lack of space for these large engines. Instead, the engines are mounted on the auxiliary vehicle. Compressors on an RC rig have an output of around 1000 cfm at 500 psi (500 L·s-1 at 3.4 MPa). Alternatively, stand-alone air compressors which have an output of 900-1150cfm at 300-350 psi each are used in sets of 2, 3, or 4, which are all routed to the rig through a multi-valve manifold.

Diamond core drilling

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Multi-combination drilling rig (capable of both diamond and reverse circulation drilling). Rig is currently set up for diamond drilling.

Diamond core drilling (Exploration diamond drilling) utilizes an annular diamond-impregnated drill bit attached to the end of hollow drill rods to cut a cylindrical core of solid rock. The diamonds used are fine to microphone industrial grade diamonds. They are set within a matrix of varying hardness, from brass to high-grade steel. Matrix hardness, diamond size and dosing can be varied according to the rock which must be cut. Holes within the bit allow water to be delivered to the cutting face. This provides three essential functions; lubrication, cooling, and removal of drill cuttings from the hole.

Diamond drilling is much slower than reverse circulation (RC) drilling due to the hardness of the ground being drilled. Drilling of 1200 to 1800 meters is common and at these depths, ground is mainly hard rock. Diamond rigs need to drill slowly to lengthen the life of drill bits and rods, which are very expensive.

Core samples are retrieved via the use of a lifter tube, a hollow tube lowered inside the rod string by a winch cable until it stops inside the core barrel. As the core is drilled, the core lifter slides over the core as it is cut. An overshot attached to the end of the winch cable is lowered inside the rod string and locks on to the backend, located on the top end of the lifter tube. The winch is retracted, pulling the lifter tube to the surface. The core does not drop out the inside of the lifter tube when lifted because a "core lifter spring," located at the bottom of the tube allows the core to move inside the tube but not fall out.

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Diamond core drill bits

Once a rod is removed from the hole, the core sample is then removed from the rod and catalogued. The Driller's offside screws the rod apart using tube clamps, then each part of the rod is taken and the core is shaken out into core trays. The core is washed, measured and broken into smaller pieces using a hammer to make it fit into the sample trays. Once catalogued, the core trays are retrieved by geologists who then analyze the core and determine if the drill site is a good location to expand future mining operations.

Diamond rigs can also be part of a multi-combination rig. Multi-combination rigs are a dual setup rig capable of operating in either a reverse circulation (RC) and diamond drilling role (though not at the same time). This is a common scenario where exploration drilling is being performed in a very isolated location. The rig is first set up to drill as an RC rig and once the desired meters are drilled, the rig is set up for diamond drilling. This way the deeper meters of the hole can be drilled without moving the rig and waiting for a diamond rig to set up on the pad

Direct Push Rigs

Direct push technology includes several types of drilling rigs and drilling equipment which advances a drill string by pushing or hammering without rotating the drill string. This should perhaps not properly be called drilling; however the same basic results (i.e. a borehole) are achieved. Direct push rigs include both cone penetration testing (CPT) rigs and direct push sampling rigs such as a PowerProbe or Geoprobe. Direct push rigs typically are limited to drilling in unconsolidated soil materials and very soft rock.

CPT rigs advance specialized testing equipment (such as electronic cones), and soil samplers using large hydraulic rams. Most CPT rigs are heavily ballasted (20 metric tons is typical) as a counter force against the pushing force of the hydraulic rams which are often rated up to 20kn. Alternatively, small, light CPT rigs and offshore CPT rigs will use anchors such as screwed-in ground anchors to create the reactive force. In ideal conditions, CPT rigs can achieve production rates of up to 250-300 meters per day.

Direct Push Drilling rigs use hydraulic cylinders and a hydraulic hammer in advancing a hollow core sampler to gather soil and groundwater samples. The speed and depth of penetration is largely dependent on the soil type, the size of the sampler, and the weight and power the rig. Direct push techniques are generally limited to shallow soil sample recovery in unconsolidated soil materials. The advantage of direct push technology is that in the right soil type it can produce a large number of high quality samples quickly and cheaply, generally from 50 to 75

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meters per day. Rather than hammering, direct push can also be combined with sonic (vibratory) methods to increase drill efficiency.

Hydraulic-rotary drilling

Oil well drilling utilizes tri-cone roller, carbide embedded, fixed-cutter diamond, or diamond-impregnated drill bits to wear away at the cutting face. This is preferred because there is no need to return intact samples to surface for assay as the objective is to reach a formation containing oil or natural gas. Sizable machinery is used, enabling depths of several kilometers to be penetrated. Rotating hollow drill pipes carry down bentonite and barite infused drilling muds to lubricate, cool, and clean the drilling bit, control down hole pressures, stabilize the wall of the borehole and remove drill cuttings. The mud travels back to the surface around the outside of the drill pipe, called the annulus. Examining rock chips extracted from the mud is known as mud logging. Another form of well logging is electronic and is frequently employed to evaluate the existence of possible oil and gas deposits in the borehole. This can take place while the well is being drilled, using Measurement While Drilling tools, or after drilling, by lowering measurement tools into the newly-drilled hole.

The rotary system of drilling was in general use in Texas in the early 1900s. It is a modification of one invented by Fauvelle in 1845, and used in the early years of the oil industry in some of the oil-producing countries in Europe. Originally pressurized water was used instead of mud, and was almost useless in hard rock before the diamond cutting bit.[1]. The main breakthrough for rotary drilling came in 1901, when Anthony Francis Lucas combined the use of a steam-driven rig and of mud instead of water in the Spindletop discovery well.[2]

The drilling and production of oil and gas can pose a safety risk and a hazard to the environment from the ignition of the entrained gas causing dangerous fires and also from the risk of oil leakage polluting water, land and groundwater. For these reasons, redundant safety systems and highly trained personnel are required by law in all countries with significant production.

Sonic (Vibratory) Drilling

A sonic drill head works by sending high frequency resonant vibrations down the drill string to the drill bit, while the operator controls these frequencies to suit the specific conditions of the soil/rock geology.

Resonance magnifies the amplitude of the drill bit, which fluidizes the soil particles at the bit face, allowing for fast and easy penetration through most geological formations. An internal spring system isolates these vibrational forces from the rest of the drill rig.

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An oil rig

Drill technology has advanced steadily since the 19th century. However, there are several basic limiting factors which will determine the depth to which a bore hole can be sunk.

All holes must maintain outer diameter; the diameter of the hole must remain wider than the diameter of the rods or the rods cannot turn in the hole and progress cannot continue. Friction caused by the drilling operation will tend to reduce the outside diameter of the drill bit. This applies to all drilling methods, except that in diamond core drilling and oil well drilling the use of thinner rods and casing may permit the hole to continue. Casing is simply a hollow sheath which protects the hole against collapse during drilling, and is often made of metal or PVC. Often diamond holes will start off at a large diameter and when outside diameter is lost, thinner rods put down inside casing to continue, until finally the hole becomes too thin. Alternatively, the hole can be reamed.

For percussion techniques, the main limitation is air pressure. Air must be delivered to the piston at sufficient pressure to activate the reciprocating action, and in turn drive the head into the rock with sufficient strength to fracture and pulverize it. With depth, volume is added to the in-rod string, requiring larger compressors to achieve operational pressures. Secondly, groundwater is ubiquitous, and increases in pressure with depth in the ground. The air inside the rod string must be pressurized enough to overcome this water pressure at the bit face. Then, the air must be able to carry the rock fragments to surface. This is why depths in excess of 500 m for reverse circulation drilling are rarely achieved, because the cost is prohibitive and approaches the threshold at which diamond core drilling is more economic.

Diamond drilling can routinely achieve depths in excess of 1200 m. In cases where money is no issue, extreme depths have been achieved because there is no requirement to overcome water pressure. However, circulation must be maintained to return the drill cuttings to surface, and more importantly to maintain cooling and lubrication of the cutting surface.

Without sufficient lubrication and cooling, the matrix of the drill bit will soften. While diamond is one of the hardest substances known to man at 10 on the Mohs hardness scale, it must remain firmly in the matrix to achieve cutting. Weight on bit, the force exerted on the cutting face of the bit by the drill rods in the hole above the bit, must also be monitored.

A unique drilling operation in deep ocean water was named Mohole.25

Types of Drilling Fluid

Many types of drilling fluids are used on a day to day basis. Some wells require that different types be used at different parts in the hole, or that some types be used in combination with others. The various types of fluid generally fall into a few broad categories:[1]

Air - compressed air is pumped either down the bore holes annular space or down the drill string itself.

Air/water - Same as above, with water added to increase viscosity, flush the hole, provide more cooling, and/or to control dust.

Air/polymer - A specially formulated chemical, most often referred to as a type of polymer, is added to the water & air mixture to create specific conditions. A foaming agent is a good example of a polymer.

Water - Water by itself is pumped to do very specific things in very specific formations. Water-Based Mud (WBM) - A most basic water-based mud system begins with water,

then clays and other chemicals are incorporated into the water to create a homogenous blend resembling something between chocolate milk and a malt (depending on viscosity). The clay (called "shale" in its rock form) is usually a combination of native clays that are disolved into the fluid while drilling, or specific types of clay that are processed and sold as additives for the WBM system. The most common of these is bentonite, frequently referred to in the oilfield as "gel". Gel likely makes reference to the fact that while the fluid is being pumped, it can be very thin and free-flowing (like chocolate milk), though when pumping is stopped, the static fluid builds a "gel" structure that resists flow. When an adequate pumping force is applied to "break the gel", flow resumes and the fluid returns to its previously free-flowing state. Many other chemicals (e.g. Potassium Formate) are added to a WBM system to achieve various effects, including: viscosity control, shale stability, enhance drilling rate of penetration, cooling and lubricating of equipment

Logging of well

Well design is keyMaximizing the net present value from coal bed methane (CBM) production requires maximizing the reserves and rate of gas extraction while keeping costs down. Optimizing well design, placement and completion, as well as stimulation and production, are key elements of this process. A successful project requires knowledge of the subsurface characteristics of the target CBM reservoir:

← location and distribution of the coal gas reserves ← producibility of these reserves ← mechanical characteristics of the coals and surrounding beds ← likelihood of water production from adjacent aquifers ← Potential of commingled gas production from adjacent reservoirs.

Well evaluation is the primary means of delivering this information. Wireline geophysical logs, in particular, provide rapid measurements that can be used in wellsite decision-making.

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Full range of well evaluation services

Gas adsorbed to coal cannot be measured directly, but in-situ gas content can be derived by correlating the coal properties, measured with logs, to the coal composition and gas content of representative core analyses. Coal cleat porosity is the primary mechanism controlling gas producibility and is also difficult to measure directly. Proven Schlumberger logging techniques for delivering these key CBM properties in situ include

← traditional logs, such as the high-resolution density log, linked with innovative analysis algorithms to develop local models derived from existing core and production data

← Advanced logs, such as geochemical logs, with processing and analysis tailored to the specific needs of CBM, providing answers that are more accurate and comprehensive.

Cased hole geochemical loggingtwo cased hole tools in particular, the ECS Elemental Capture Spectroscopy stoned and the RST Reservoir Saturation Tool, increase operational efficiency by providing valuable CBM evaluation information without the need for open hole logging. These tools directly measure the chemical makeup of coal and ash mineralogy and are used to estimate the discrete and cumulative coal gas volume and the degree of cleating.

Total coal gas content and the gas adsorption isotherm at discrete depths are determined from the coal and ash content measurements by using an empirical relationship derived from proximate analysis and gas desorption/adsorption tests performed on core samples. This relationship is applied within a physical gas adsorption model, such as the Longmuir equation.

The degree of cleating at discrete depths is indicated by geochemical log measurements of the mineral ash constituents of coal beds. These are typically carbonate, quartz, pyrite and clay. In order to determine the degree of cleating, relationships that use the cutoffs on the mineral ash volume measurements have been developed. The inferred degree of cleating, in turn, indicates the gas producibility of the coal at that depth. Cleating and coal gas content estimates are enhanced when coal proximate, gas desorption/adsorption analysis data and CBM production data are available from at least one well in the field.

The geochemical measurement is largely unaffected by fluid in the well, and the contribution of the casing and annular fill to the overall measurement can be easily subtracted because the depth of investigation extends to 7 in. The ECS stoned delivers greater measurement precision than the RST tool. However, the RST tool can be run in casing as small as 2 in., whereas the ECS stoned is limited to casing of 6 in. or larger. In addition, the RST tool uses a pulsed neutron generator, whereas the ECS stoned uses a chemical radioactive neutron source.

As well as providing evaluation of the coals, both tools deliver accurate litho logy characterization throughout the logged borehole. The geochemical log has a standard vertical resolution of 20 in., but 8-in. vertical resolution is possible if a high-resolution neutron porosity log is also run.

High-resolution density measurementThe standard Schlumberger open hole logging suite for CBM well evaluation includes both bulk density and gamma ray measurements. It provides high-resolution delineation of the depth and thickness of coals because the bulk density measurement has a vertical resolution

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as high as 2 in. Coal quality is indicated by the magnitude of the bulk density drop. A local model can be developed to quantitatively predict coal grade, rank and gas content from the log. This is achieved by calibrating the density and coincident Peor the neutron porosity measurements with reliable core coal proximate, core gas content and production data.

Openhole geochemical loggingA more accurate and reliable estimate of gas reserves, coal quality and degree of cleating can be obtained by open hole geochemical logging with the ECS or RST tools. The geochemical log is a dry measurement with a 7-in. depth of investigation allowing both washouts and other environmental effects to be eliminated. Openhole geochemical logs can also provide a "ground-truth" for subtracting contributions due to casing and annular fill.

Combining the geochemical log with a density measurement enables a more general coal gas estimate to be made and increases the coal bed vertical resolution from 20 in. to as sharp as 2 in. In addition, performing a full "wet" formation evaluation with density porosity helps reach a decision on completion and stimulation methodology. For example, the litho logy and porosity of beds adjacent to the coal indicate how much water these beds may produce, which is important in deciding whether to perforate the coal or perforate an adjacent bed before fracturing into the coal.

Integrated open hole logging suiteThe Platform Express suite of logs adds resistively, microresistivity and neutron porosity to the stand-alone density log. This provides a coal cleat porosity estimate from the resistivity and classical formation evaluation along with the coal quality and gas content estimate. The Platform Express suite also allows computation of synthetic compressional and shear velocities, using neural network local models. These velocities can be used to estimate mechanical properties and stress profiles for stimulation design.

Sonic imaging measurementsA direct calculation of mechanical properties and stress profiles for stimulation design can be made when the DSI tool is run. This tool measures actual compressional and shear velocities in coals and surrounding beds. It also allows computation of velocity anisotropy to assist in advanced oriented completions, for CBM basin evaluation, or as a secondary local indicator of cleating.

Well Completion

Once the design well depth is reached, the formation must be tested and evaluated to determine whether the well will be completed for production, or plugged and abandoned.

To complete the well production, casing is installed and cemented and the drilling rig is dismantled and moved to the next site.

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A service rig is brought in to perforate the production casing and run production tubing. If no further pre-production servicing is needed, the christmas tree is installed and production begins.

. Completed well . Well completion service rig

Well completion for cased hole activities include:← Conducting Drill Stem Test ← Setting Production Casing ← Installing Production Tubing ← Starting Production Flow

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← Beam Pumping Units ←←

Conducting Drill Stem Test

To determine the potential of a producing formation, the operator may order a drill stem test (DS

The DST crew makes up the test tool on the bottom of Weight is applied to the tool to expand a hard rubber sealer called

a packer.

Opening the tool ports allows the formation pressure to be tested. This process enables workers to determine whether the

Well can be produced.

. Drill stem test assembly

Setting Production Casing

Production casing is the final casing in a well. It can be set from the bottom to the top.

Sometimes a production liner is installed.

This casing is set the same as other casings, then cemented in place. Installing production casing

Installing Production Tubing

A well is usually produced through tubing inserted down the production casing.

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Oil and gas is produced more effectively through this smaller-diameter tubing than through the large-diameter production casing.

Joints of tubing are joined together with couplings to make up a tubing string. Tubing is run into the well much the same as casing, but tubing is smaller in diameter and is removable.

The steps for this activity are:

← Tubing elevators are used to lift tubing from the rack to the rig floor.

← The joint is stabbed into the string, which is suspended in the well, with air slips.

← Power tongs are used to make-up tubing. Tubing head← This process is repeated until tubing installation is complete.← The tubing hanger is installed at the wellhead. ←

The steps for this activity are:

← Tubing elevators are used to lift tubing from the

← rack to the rig floor.← The joint is stabbed into the string, ← this is suspended in the well, with air slips.← Power tongs are used to make-up tubing.← This process is repeated until tubing installation is complete.

The tubing hanger is installed at the wellhead. Installing coil tubing← New technology allows tubing to be manufactured in a continuous coil, without joints. Coiled

tubing is inserted into the well down the production casing without the need for tongs, slips, or elevators, which takes considerably less time to run.

Starting Production Flow

Production flow is started by washing in the well and setting the packer. Washing in means to pump in water or brine to flush out the drilling fluid.

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Usually this is enough to start the well flowing. If not, then the well may need to be unloaded. This means to swab the well to remove some of the brine. If this does not work the flow might be started by pumping high-pressure gas into the well before setting the packer.

If the well does not flow on its own, well stimulation or artificial lift may need to be considered.

Production flow

Beam Pumping Units

If the well doesn't produce adequately, a beam pumping unit may be installed.

There are four basic types of beam pumping units. Three involve a walking beam, which seesaws to provide the up and down reciprocating motion to power the pump.

The fourth reciprocates by winding a cable on and off a rotating drum. The job of all four types is to change the circular motion of an engine to the reciprocating motion of the pump. Beam pumping units

The pump units are brought in disassembled

on trucks and off-loaded onsite.

The many parts of the pump unit include l

heavy metal pieces that need to be assembled.

Assembling beam pumping unit

Open hole

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Since open hole completion work has experienced a resurgence of popularity, some of the techniques inherent in this style of completion are relatively new to some of the people involved in that work. One aspect of this type of completion is the need to use a careful system of depth control. Whereas in a cased hole completion the perf guns are guided by a correlating gamma ray log, the open hole work must be done in a similar fashion except that one extra tool is needed. This tool is called a steel line and the steel line measurement or SLM as it is referred to, must be used continuously throughout the open hole procedure. This is so that any differences of depth between the original open hole logs and the rig' s steel line are compensated for, permitting the placement of the treatment accurately in the target zones.

The normal procedure in open hole completions involves "notching" or cutting a groove in the formation using a blast of sand and air through a jet on the end of a string of tubing. It is at this point that the correlation of the logger's depths to the steel line used by the rig occurs. With the tubing string run into the well, a slim-hole gamma/CCL log is used to locate the position of the tool on the end of the tubing relative to the formation. This is an important step since all other depths needed during the procedure will be determined with this steel line, including packer sets and plug back depths. This procedure is necessary because, for various reasons, the depth determined by the SLM may be different from the original depths recorded on the open hole logs. The calibration of logging tools, reference points from which the logs were run and hole conditions may all contribute to this difference.

Several steps can be taken to enhance the accuracy and reliability of the SLM. First, a permanent reference point at the surface should be established from which the correlation gamma ray will be measured as well as all future depths during the completion. Usually the top of the collar on the water string is as good a choice as any since this casing will usually not change for the duration of the completion. Next, when running the tubing string for the notch, place a short joint, perhaps ten feet long, on the bottom of the string. With the known length of this joint and the notch tool installed, the exact position of the notch tool can be noted with the aid of the CCL log. I have found it helpful to always set the tubing a known distance above the reference point so that the calculations for the SLM will always use this same amount. When working repeatedly with the same rig crew, this is not a difficult request and can add to the procedural regularity of the operation.

At this point, the most important series of calculations will be made. In doing the calculations a pre-established format or work sheet is helpful. It is a good idea to record at least the minimum pertinent data on this sheet, including the well number or other identification, date, log zero or permanent reference point such as "top of the 7" casing" and perhaps the name of the target formation and its depth from the open hole logs. Once the SLM is run inside the tubing, it should be noted and labeled as such on the work sheet. If after the gamma ray log is run it is determined that any tubing needs to be added or removed to facilitate the notch procedure, the change in tubing should be shown in the SLM. If more than three joints are added or removed, it may be wise to re-run the SLM.

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Next, the slim-hole gamma ray CCL tool is run. Common practice in the Appalachian Basin is to use an expanded scale of either 20 or 25 inches per 100 feet of hole. Of course it is not necessary to log much more that the zone of interest and perhaps a couple of additional correlating marker beds or stringers. Once the log is run, the completion engineer can compare it to the original open hole logs and identify the desired location of the notch points. With this information and the calculation of the SLM it can then be determined how far the notch tool must be raised to cut the first notch. If more than one notch is desired, the same calculation can be made proceeding from the lowest notch point in the hold towards the surface. If it becomes necessary to remove more than

three joints of tubing while proceeding with the notch procedure, it is wise to repeat the SLM and gamma/CCL procedure.

Once notches have been cut and the tubing pulled, a confirmation log can be obtained using a three arm caliper and gamma ray. The notches should appear as slight hole enlargements on the caliper, perhaps as much as three-fourths to an inch deep depending on the hardness of the formation. During the balance of the treatment procedure of the well, the SLM notch points will be used once again for calculation of the depths to wash-down and packer set. On frac day, in addition to the pipe tally, a cross hair affixed to the bottom of the frac packer makes it possible to measure the depth of the packer with a SLM prior to the start of the wash-down of the first zone. This adds to the assurance that the zone being treated has been accurately isolated.

While some parts of this procedure may seem too cautious, it would seem possible that in the past a causal attitude toward depth measurements during the completion work contributed to wells that should have been better. In one case of reworking a well that had been walked away from by the operator, a three arm caliper was first run to check the depth of the original notches. It was determined that they had been cut in the zone but not in the best porosity. It can only be assumed that the treatment did not penetrate the portion of the zone with the most gas. With accurate depth control we re-notched and re-fraced the well and the result was a producible well where before there has been little production and considerable water influx.

In conclusion, the extra care and time that it may take to utilize a precise method of measurement and correlation during open hole work should pay off in dividends from a more productive well.

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Well stimulation

Hydraulic fracturing

Though most coals are naturally fractured, you normally need to hydraulically fracture coal seams to produce economic gas flow rates.

In the reservoir, methane gas is adsorbed onto The surface of the coal.After the reservoir pressure is lowered and the gas desorbs from the coal,

It flows through the natural fractures in the coal. For gas to flow to the well bore at economical rateseffective communication must be established between the natural coal fractures or cleats and the well bore. Your well is obstructed by silt, sediment or deposits

The most effective way to create this communication is well obstruction by fracturing the coal seam.

In fracturing, large volumes of fluid and sand are pumped at high Pressure down the well bore.

The fluid opens a crack in the coal, and afterthe fluid is removed, the sand remains in place to keep the new channel Open.

The resulting proppant-filled fracture provides a flow path into the well bore for water and gas.

When successful, hydraulic fracturingcan greatly increase methane production from coal seams.

Water with proppant sand and chemical injected with high pr.

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Though much conventional fracturing technology can be appliedto coal bed fracturing, many techniques have been developed specifically for coal bed methane wells. This chapter will explain these techniquesand help you in

• Performing a Minifracture Test• Planning a Fracture Treatment Design• Preparing for a Fracture Treatment• Performing a Fracture Treatment• Evaluating a Fracture Treatment

Obstruction forcing out

Open-hole cavity completion techniques

The typical procedure for large cavity creation involves injecting air along with water into the well bottom. As sufficient pressure is built in the well it is suddenly released. Differential pressure at the coal seam interface causes coal bed methane to suddenly expand, resulting in coal matrix bursting and sloughing into the well bore. The procedure is repeated for days and weeks.

Another known approach is similar but using high-density fluid for creating pressure in the well.

In both cases hydraulic valves at the wellhead are used for pressure release

The efficiency of such a procedure greatly depends on the time of pressure release. The shorter the time of pressure release, the more efficient the process. While using the hydraulic valves, this time is seconds. During this relatively long time, coal bed methane may escape into the well bore through cleats, with little impact to the matrix.

\

Enhanced CBM Recovery

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The CBM industry is exploring new methods of enhancing gas production from older

fields that have produced for more than 10 years. Several companies are experimenting with the injection of nitrogen (N) and carbon dioxide (CO2) into the coal bed to displace methane along the coal face cleats.

Generally, the N2 and/or CO2 molecules replace the methane molecules within the cleats at a ratio of approximately 4 to 1. This forced gas exchange has resulted in elevated methane production rates as compared to just lowering the hydrostatic pressure. Injection of nitrogen, usually generated by manufactured gas plants, reduces the partial pressure and therefore the concentration of methane in the coals in the fracture system.

Even though the partial pressure is reduced, the total pressure is generally constant (depending on whether or not the seams hydrostatic pressure is being lowered) and the fluids maintain head that drives liquids to the production wells. It is theorized that nitrogen injection affects methane production from the coal seam via inert gas stripping and sorption displacement. Coals can replace 25% to 50% of their methane storage capacity with nitrogen.

This enhanced production method has a beneficial side effect—the sequestering of CO2. Carbon dioxide is a common by-product of many industrial processes and is considered a green house gas. The sequestering of CO2 lowers the amount available to be exhausted to the atmosphere and helps the United States meet its goal for reduced CO2 emissions. Laboratory studies indicate that coal adsorbs nearly twice as much volume of CO2 as methane. There are some concerns, however, that injection of CO2 into mineable coals presents a safety hazard, as the mines are required to have a limit of 3% CO2 by volume in the mine air. One potential method for reducing CO2 levels in the mine air is to use a mixture of CO2 and other gases, such as nitrogen. Studies indicate that for each volume of nitrogen that is injected, two volumes of methane are produced.

There is growing interest in mixed nitrogen/CO2 injection for two reasons: there may be a synergy of production mechanisms, and its use would result in the lowering of CO2 levels in the mine air (EPA 2002a). More research is needed in this arena, but preliminary results are promising for both CBM production and CO2 sequestering.

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Horizontal Drilling

H

Horizontal drilling

The production of CBM from eastern coals is similar to the western coals except for the use ofhorizontal wellbores and extensive use of fracturing to enhance production. With the coals being

of higher rank, the methane content per ton of coal is typically higher, but requires additionalenhancement to the natural fractures in many areas to maximize production. Production rates of

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CBM depend upon local gas content of the coal, local permeability of the coals, hydrostaticpressure in the coal seam aquifer, completion techniques, and production techniques.

Production CBM

1 Dewatering stage:

2. Production stage

3. Decline stage

1 Dewatering stage:

Most coal seams with gas in commercial quantities contain water that is produced along with the gas. The coal zones typically require local or regional dewatering before commercial gas production can be achieved, and the key to economic production is cost-effective reservoir dewatering techniques.

Most producible coals have a natural cleat or fracture structure that serves as a flow path for the water and desorbed gas. Production normally requires dewatering one or more coal zones to reduce the in-situ reservoir pressure below the "critical desorption pressure" at which methane is released from the coals and flows with the water to the area of pressure drop at the well bore.

A wide variety of completion and treatment techniques are used, depending on the coal structure, thickness, porosity and relative permeability. However, regardless of the well configuration and completion treatment, the operational objectives require maintaining the lowest possible reservoir pressure to maximize the gas desorption rate, and reducing reservoir pressure requires pumping the fluid level in the well down to the lowest possible point.

CBM well pumping requirements present challenges due to the nature of the production and completion methods. The well tubulars are configured so that gas will migrate to the surface in the annular space between the production tubing and the casing. A pump is typically landed as low as possible in the well to maximize fluid drawdown, which can result in periods of reduced

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fluid volumes and, therefore, increasing internal pump temperatures. Plus, minimal fluid levels over the pump and a foamy liquid/gas interface can cause gas to migrate to the pump intake, resulting in internal compression and operating temperature increases. Another issue for CBM pumping systems is solids in the fluid. Depending on the type of well completion used to stimulate the coals, a pump can be initially inundated with fracture proppant. Coal particles also can be carried in the fluid. Both proppant and coal fines are abrasive and can damage the pumping system components. These production challenges can mean escalating operating costs, potentially making CBM projects economically unfeasible. Consequently, a sustainable and reliable pumping system is critical to the positive payout of a well or field.

In addition to adverse pumping conditions, another major consideration for CBM production systems is operating costs. Historically, revenue from CBM production has been relatively marginal due to water handling and disposal costs as well as costs associated with compressing the gas from as low as 1 psi to a pipeline entry pressure of 300

2. Production stage

In this stage gas starts continuously flow from well and the stage when gas is being sent to the commercial market. Here goes the maximum production of the well. this is the stable production for the gas.

3. Decline stage

In this stage the quantity of gas decreases and production of water also decreasesThis is the stage when some recovery methods are being applied to recover the gas

Coal bed methane (CBM) or coal seam gas (CSG) production is accelerating in many countries, as new basins, new plays, new completion techniques are making these huge resources economical to produce. Australia, for example, is at the forefront of new developments, with CBM/CSG production rates having increased by 300% in the last year and dozens of new projects under development. Many of these are being developed to fill an identified strong market need in the Asia Pacific, but also in the USA, for clean burning methane, to be exported in the form of LNG. These LNG plants are huge multi-billion dollar investments, and have to be fed by multi-billion dollar field developments and operations.

Additionally, Australia, like other countries, is soon to embark on an Emissions Trading Scheme, increasing the demand for clean burning fuels like methane, which is expected to displace coal for power generation. Production Management Best Practices are required to keep the fields producing at maximum total-life economic returns, whilst understanding and managing the risks involved in maintaining the total supply chain to both domestic and export markets.

The teams for each best practice area will consider this initial (non exhaustive) sub-set of activities & strategies:

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Reservoir Management: Reservoir surveillance; reservoir performance;

integrated modeling; benchmarking; reservoir issues affecting production; water and gas quality.

Well Management: Well surveillance; well automation; well modeling; well deliverability; artificial lift; infill drilling; completion techniques; production enhancement.

Production Systems and Facilities Management:  Gathering Systems; flow assurance and bottleneck prevention/debottlenecking; gas and water separation; infield compression; facilities shutdowns.

Protecting the Environment While Maximizing Production: Water and waste management; emissions minimization; noise issues; regulatory environment; disturbance minimization.

Social Performance: Safety; Community Impact; Regulatory; Staffing and Training.

Production

Most CBM reservoirs initially produce only water because the cleats are filled withwater. Typically, water must be produced continuously from coal seams to reducereservoir pressure and release the gas. The cost to treat and dispose the produced watercan be a critical factor in the economics of a coal bed methane project. Once the pressurein the cleat system is lowered by water production to the “critical desorption pressure,”gas will desorb from the matrix. Critical desorption pressure, as illustrated on Figure 5, isthe pressure on the sorption isotherm that corresponds to the initial gas content. As thedesorption process continues, a free methane gas saturation builds up within the cleatsystem. Once the gas saturation exceeds the critical gas saturation, the desorbed gas willflow along with water through the cleat system to the production well.Gas desorption from the matrix surface in turn causes molecular diffusion to occur withinthe coal matrix. The diffusion through the coal matrix is controlled by the concentrationgradient and can be described by Fick’s Law:= 2.697σ ρ ( − ) gm c c c s q D V G GWhere:gm q = Gas production (diffusion) rate, MCF/dayσ = matrix shape factor, dimensionlessD = matrix diffusivity constant, sec-1

c V = Matrix volume, ft3ρc

= Matrix Density, g/cm3

c G = Average matrix gas content, SCF/tonDiffusivity and shape factor are usually combined into one parameter, referred to assorption time, as follows:1Dτσ=Sorption time (τ ) is the time required to desorb 63.2 percent of the initial gas volume.The Sorption time characterizes the diffusion effects and generally is determined fromdesorption test results.

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Darcy’s law can adequately represent the two-phase flow in the cleat system. Cleatsystem porosity, permeability and relative permeability control fluid flow within the cleatsystem. As the desorption process continues, gas saturation within the cleat systemIncreases and flow of methane becomes increasingly more dominant. Thus, waterproduction declines rapidly until the gas rate reaches the peak value and water saturationapproaches the irreducible water saturation. The typical production behavior of a CBMreservoir is illustrated in Figure 8. After the peak gas rate production is achieved, thebehavior of CBM reservoirs becomes similar to conventional gas reservoirs.Coal bed methane production behavior is complex and difficult to predict or analyze,especially at the early stages of recovery. This is because gas production from CBMreservoirs is governed by the complex interaction of single-phase gas diffusion throughthe micro pore system (matrix) and two-phase gas and water flow through the macro pore(cleat) system, that are coupled through the desorption process. Therefore, conventionalreservoir engineering techniques cannot be used to predict CBM production behavior.The best tool to predict the performance of CBM reservoirs is a numerical reservoirsimulator that incorporates the unique flow and storage characteristics of CBM reservoirsand accounts for various mechanisms that control CBM production. In addition, historymatching with a simulator is one of the key tools for determining reservoir parameters

that are often difficult to obtain by other techniques

Coal bed methane (CBM) is the fastest growing unconventional natural gas resource, and

energy companies are rapidly climbing the learning curve to economically maximize production

from coal seams throughout the world.

Today, there are an estimated 30,000 producing CBM wells in the United States - by far the

most active region of the world for CBM production. However, activity in Canada has increased

since 2000, when there were less than 200 wells, to approximately 3,900 wells today,

producing over 150 MMcfgd. Reserve estimates vary depending on the reporting agency;

however, the most consistent figures indicate the mature producing basins in the United States

account for an estimated 17 Tcf of recoverable reserves, and emerging developing US basins

have an estimated 35 Tcf of gas reserves. The bulk of US reserves are in the Rocky Mountain

basins as well as the Black Warrior Basin of Alabama and the Appalachian Basin. The 700 Tcf

of estimated reserves in Canada include 500 Tcf in Alberta, where much of the activity is

taking place today, with the balance primarily in British Columbia, Saskatchewan and Nova

Scotia.

Production concerns

Most coal seams with gas in commercial quantities contain water that is produced along with

the gas. The coal zones typically require local or regional dewatering before commercial gas

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production can be achieved, and the key to economic production is cost-effective reservoir

dewatering techniques. CBM plays such as the Powder River Basin, Black Warrior Basin,

Manville coals of Alberta and coals in Australia all require dewatering to realize economically

attractive recovery rates.

Most producible coals have a natural cleat or fracture structure that serves as a flow path for

the water and desorbed gas. Production normally requires dewatering one or more coal zones

to reduce the in-situ reservoir pressure below the "critical desorption pressure" at which

methane is released from the coals and flows with the water to the area of pressure drop at the

well bore.

A wide variety of completion and treatment techniques are used, depending on the coal

structure, thickness, porosity and relative permeability. However, regardless of the well

configuration and completion treatment, the operational objectives require maintaining the

lowest possible reservoir pressure to maximize the gas desorption rate, and reducing reservoir

pressure requires pumping the fluid level in the well down to the lowest possible point.

CBM well pumping requirements present challenges due to the nature of the production and

completion methods. The well tubulars are configured so that gas will migrate to the surface in

the annular space between the production tubing and the casing. A pump is typically landed as

low as possible in the well to maximize fluid drawdown, which can result in periods of reduced

fluid volumes and, therefore, increasing internal pump temperatures. Plus, minimal fluid levels

over the pump and a foamy liquid/gas interface can cause gas to migrate to the pump intake,

resulting in internal compression and operating temperature increases.

Another issue for CBM pumping systems is solids in the fluid. Depending on the type of well

completion used to stimulate the coals, a pump can be initially inundated with fracture

proppant. Coal particles also can be carried in the fluid. Both proppant and coal fines are

abrasive and can damage the pumping system components.

These production challenges can mean escalating operating costs, potentially making CBM

projects economically unfeasible. Consequently, a sustainable and reliable pumping system is

critical to the positive payout of a well or field.

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In addition to adverse pumping conditions, another major consideration for CBM production

systems is operating costs. Historically, revenue from CBM production has been relatively

marginal due to water handling and disposal costs as well as costs associated with

compressing the gas from as low as 1 psi to a pipeline entry pressure of 300 psi to 1,500 psi.

With these operational and economic hurdles to overcome, operators have challenged pump

manufacturers to develop cost-effective solutions.

Artificial lift options

Traditionally, electrical submersible water well systems and rod-driven progressing cavity

pumping systems (PCPs) have been employed to dewater CBM wells. However, reliability has

been an issue with water well equipment, while cost considerations have stymied PCP and

more rugged oilfield electrical submersible pumping systems. To overcome these issues,

oilfield service companies have designed pumping systems specifically for CBM applications,

providing more rugged yet cost-effective equipment.

For example, Centrilift developed a 30 hp drive head for rod-driven progressing cavity pumping

systems as a more cost-effective fit for the 10 hp to 30 hp applications typical of shallow CBM

wells. PCP systems have been used in CBM wells since 1986, both as the primary dewatering

system and as a solution for troublesome wells, since PCPs can effectively pump coal fines,

sand particles and gaseous fluids. Plus, PCP is a positive displacement system with the output

rate directly tied to the speed of the pump. This feature allows the system to be adjusted via

pump speed to match the decline curve of the water production, eliminating over-pumping the

well.

The single or double helix design of the steel rotor in a PCP pump, coupled with the stator,

which is a steel tube with an elastomer permanently bonded inside, provides a design with

sealed cavities within the pump. As this seal line moves up along the pump, any solid particles

are trapped between the rotor and stator and temporarily deflect the elastomer until the seal

line passes and the solids re-enter the fluid stream.

Gas impacts a pump by taking up space meant for fluid and, in many systems, can cause

grossly inefficient fluid production, intermittent production or a gas-locked pump. The main

effect of gas on PCPs is a decrease of volumetric efficiencies. A PCP of a given capacity

moves a given volume per revolution, regardless of whether that volume is oil, gas or some

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combination. As a general rule, 40% free gas at the pump intake is considered acceptable and

will not adversely impact pump life.

PCP elastomers balance the needs of CBM production. The elastomer is flexible enough to

provide the deflection needed to pass solids through the pump without gross erosion of the

elastomer or the chrome plate of the rotor. The elastomer constituents and structural matrix

are designed to remain stable while in operation in order to resist expansion that can occur

due to decompression caused by gas migration into the rubber as well as resisting swelling

from exposure to water.

Applications

As with any oil and gas play, specific applica-tions dictate the choice of production equipment.

While PCPs are suited for wells with abrasive conditions, electrical submersible pumping

(ESP) systems are a good choice for wells with water volumes above 1,200 bbl of fluid per

day.

Electrical submersible pumping systems have been used in CBM wells since about 1999, but

initially water well systems were employed due to the low cost of the equipment. However,

water well systems cannot handle coal fines and other solids. During the initial dewatering

stage, the water is relatively clean (in wells where sand proppant is not used during the

completion), but as the well is drawn down, more solids enter the system. As a result, the

water well equipment runs reasonably well for a period of time but then fails as the coal fines

increase.

As the CBM market has matured, a growing number of producers with oil industry

backgrounds have jumped into these unconventional plays, and those companies have sought

better equipment choices. Oilfield service companies were approached to supply hybrid ESP

systems that are more robust than water well systems but still cost-effective for CBM wells.

The ideal solution was an oilfield-type pump, which is more resistant to abrasives, with a water

well-type motor and surface package.

In addition to a more robust design, oilfield service companies were challenged to develop a 45

system that could go deeper and fit in smaller casing sizes. Traditional water well motors rated

over 10 hp are too large for small casing, and below about 2,000 ft (610 m) the water

temperature exceeds the limits of water well systems. To overcome these challenges, Centrilift

recently developed its 450 CBM motor with an integral motor/seal design.

The 450 CBM motor is a redesign of the conventional oilfield 450 motor train with no threads

on the ends - the head and base are welded. A single shaft is used for the motor and the

single chamber seal. The thrust bearing and motor carry the pump load versus both a motor

and seal thrust bearing in a standard oilfield configuration. The motor leads for the electrical

cable come directly out of the motor head, unlike a standard motor that has a separate plug-in

connector.

The biggest challenges for the new design were the motor head redesign, making it part of the

seal. Also, there is only one mechanical seal in the unit, so to provide some redundancy in the

event of a seal leak, a lip seal was included under the mechanical seal at a dramatic cost

savings compared to the traditional design.

To further reduce operating costs, the motor is pre-filled and pre-serviced and can be installed

by the operator, which eliminates field service costs. Additionally, the cable splice design is

common to operators, making installation by the operator feasible.

The 450 CBM motor is designed for applications from 20 hp to 30 hp and up to 2,200 ft (670

m) deep. The motor is run below the perforations. Down to 2,200 ft, the water temperature is

cool enough to keep the motor cool. The most significant advantage of the new motor is the

cost savings associated with drilling smaller cased wells versus the 7-in. casing required for

water well systems over 10 hp.

An operating company exploring for and producing CBM from vertical wells in the eastern

United States has increased its anticipated 5-year cumulative CBM production by 40%, and its

estimated ultimate recovery (EUR) by 57% in three wells selected for a pilot study. The

production improvement was observed in a pilot project of three CBM wells that were in the

early development phase of the CBM well lifecycle. The five phases of CBM wells are (1)

regional resources reconnaissance (2) local asset evaluation, (3) early development, (4)

mature development and (5) declining production.

In the field trials, the service company employed a remedial stimulation service (RSS) that provides a back flush to help remove particulate damage while treating formation particulates (coal, shales, clays) to restrict their mobility. Chemicals included in the treating solution initially

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act as "clotbusters," breaking apart the internal particle bridges and agglomerates of coal fines and precipitates, then act as "clot-formers," imparting a tacky surface to the coal particle surfaces. Coal particles then adhere to each other, and the clots adhere to formation features and proppant grains away from the fluid flowpaths. This process, for which a patent is pending, results in a highly conductive flowpath from the coal matrix to the fracture and well bore, and significantly delays re-plugging.

In CBM reservoirs, attaining maximum differential pressure from the coal surrounding the well bore is key to effective drainage of methane through desorption.

Figures 1 through 3 show the production improvement results seen in the three trial wells. Because field trials showed the new potential of the Phase 3 field, the the operator was able to upgrade its asset. Further, the operating company is expanding its acreage position to exploit the new-found production potential provided by the RSS. All three production graphs in Figures 1 through 3, illustrating the July 2003 to June 2004 period, show significant upturn in methane production following treatments in the March - May period. The increase began after the wells were brought back to production after remedial stimulation.

Figure 1. Well 1 production increase from use of the RSS. The vertical lines in Figures 1 - 3 indicate dates of RSS treatments.

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Figure 2. Well 2 production increase from use of the RSS.

Figure 3. Well 3 production increase from use of the RSS.

How it works

Figure 4 is photomicrograph that illustrates blockage formed by clots of migrating coal fines within the propped fracture. The fines are carried toward the well bore during CBM production. To remediate the damage and prepare the well for a longer productive lifespan, the operator pumps the low-viscosity treatment fluid into the damaged fractures, breaking down the clots of coal fines and displacing the blockage away from the central flow paths within the fracture system. The well is shut-in to allow the chemical process to perform its job of locking the fines

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in place, preventing them from re-bridging and infiltrating the proppant flow paths. Some agglomerated fines will adhere to proppant and others to the formation surfaces.

Other key functions of the RSS chemistry are to (1) degrade residual organic polymers, and (2) dissolve insitu geochemical precipitates or carbonate scales that may be contributing collectively to premature production declines.

Figure 4 illustrates the tendency of coal fines to collect in pore spaces; eventually, such plugging may result in damage to permeability and conductivity. The post treatment view in Figure 5 shows fines segregated, stuck together in large groupings, and immobilized on proppant surfaces. Pore spaces are not plugged by the immobilized fines.

Background

Since the late 1990s, the production company has operated a 125-well field where production rates range from near zero to about 350 Mcf/day. After reviewing the results of the RSS in western US CBM basins, the company investigated the potential of applying RSS techniques to its fields. A new on-the-fly delivery process, improved chemistry and zonal isolation techniques were designed to increase process efficiency. A key to success for this project was to match the new remedial solution to the challenging economics involved in boosting production without drilling new wells, re-fracturing, or applying other capital-intensive options.

After review of production response, field geology, well completions and placement options, the operator decided to try the RSS, which was designed to provide the option of on-the-fly or batch-mixing processes. The chemical formulation in the RSS is designed for treating CBM wells in either a remedial post-fracture mode or in conjunction with a primary well-stimulation treatment.

Due to the first trial focus of the technology in the region in addition to a trial of the new chemistry in these coals, the batch-mix option was selected for the initial proof of concept treatments.

Figure 4. This photomicrograph of an untreated fracture shows that coal fines tend to migrate and block pore spaces, reducing

Figure 5. In this view, the RSS-treated fracture sand traps and holds migrating coal fines on the leading edge (toward the flow) of

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conductivity to the well bore.the grains, helping to prevent the fines from

plugging pore spaces.

Field summary

One of the trial objectives was to test two different methods for fluid placement in the multi-seam completions where up to 25 coal seams had been perforated and hydraulically fractured. One method used was to apply treatments down the backside, i.e., down the tubing/casing annulus, and back up the tubing, with no seam isolation. This approach, although low in cost, was not expected to return a significant production increase. However, it was used in one pilot well to establish its capability.

Figure 6 illustrates the annular application method. Note that most of the treatment fluid goes into the lower seams because the only pressure applied is the hydrostatic pressure from the fluid column; more of the pressure is applied against the lower coal seams.

Wells stimulated by this cheaper annular method yielded production increases of only 3% to 10%. Payout was 6 months of production. Although this was a positive outcome, results of using the isolation treatments were more successful from an economic result viewpoint.

Isolation treatments

The second method evaluated included in the treatment package was one that required use of a workover rig. This technique was expected to produce more effective results, since seam packages were isolated to help ensure treatment fluid was placed where needed. This approach allowed the operator the opportunity to achieve optimal treatment performance while adapting the RSS process to the challenge of multi-scam completions.

Figure 7 shows schematically how the RSS is applied to a multi-seam well. The method requires removal of the pump jack and use of a workover rig to remove production tubing and associated equipment. The many coal seams are grouped (three to five seams per group) for treatment, with the lower group treated first, the second group of seams treated second, and so on. In the illustration, the lower group of three seams has been treated and a bridge plug installed above the group to provide a new "bottom" to the well. A treating packer is set above the second group of seams, which are now being stimulated by the RSS. This process is continued from bottom up until all seams are treated.

Production improvement on the three well pilot program resulted in payouts of about 3 months, despite the added expense of using a workover rig.

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Figure 6. A remedial treatment applied through the tubing/casing annulus tends to break out

through the lower perforations because hydrostatic pressure is greater there. Upper

perforations may receive little or no stimulation

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Figure 7. Using the isolation-treatment method, production tubing is removed and the RSS

treatment is applied to small groups of perforations that are isolated from the remainder of the

perforations. In this manner, each coal seam has a greater likelihood of receiving fracture

stimulation

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CBM SURFACE FACILITY AT SINGLE WELL

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Comparison of the Technology

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Summery of specific options for utilization of Coal-bed methane

a. Power Generation - CBM can be ideal fuel for co-generation Power plants to bring in higherefficiency and is preferred fuel for new thermal power plant on count of lower capital investment and higher operational efficiency.

b. Auto Fuel in form of Compressed Natural Gas (CNG) - CNG is already an established clean and environment friendly fuel. Depending upon the availability of CBM, this could be a good end use. Utilization of recovered CBM as fuel in form of CNG for mine dump truck is a good option.

c. Feed stock for Fertilizer – Many of the fertilizer plants in the vicinity of coal mines where coal bed methane is drained, have started utilizing fuel oil as feedstock for its cracker complex.

d. Use of CBM at Steel Plants - Blast furnace operations use metallurgical coke to produce most of the energy required to melt the iron ore to iron. Since coke is becoming increasingly expensive, in the countries where CBM is available, the steel industry is seeking low-capital options that reduce coke consumption, increase productivity and reduce operating costs.

e. Fuel for Industrial Use - It may provide an economical fuel for a number of industries likecement plant, refractory, steel rolling mills etc.

f. CBM use in Methanol production - Methanol is a key component of many products. Methanoland gasoline blends are common in many countries for use in road vehicles. Formaldehyde resinsand acetic acid are the major raw material in the chemical industry, manufactured from methanol.

g. Other uses - Besides above, option for linkages of coal-bed methane through cross country pipe lines may be considered .

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Conclusion:India is third largest producer of coal in the world. If recovered effectively, coal bedmethane (CBM) gas associated with coal reserves and emitted during coal mining could be aSignificant potential source of energy in coal-rich but often economically poor regions.Utilization of CBM would introduce a clean energy source and reduce local pollution andemissions of greenhouse gases. It is important to note that methane is a greenhouse gasapproximately 21 times more potent than carbon dioxide.

CBM in India is still at an early stage of development with both public and private companieslooking to develop the skills and services in-country to become the market leader.

With the new economic policy, India has made rapid strides in development in the past decade. This has increased demand for energy, which is now creating an ever-increasinggap of demand and supply. To bridge this gap, various sources of energy are being considered. Areas presentlybeing explored include gas hydrates, basin centred gas, shale gas, tight gas, basement oil, geo-bioreactors etc. Mostof these ‘unconventional’ hydrocarbon resources are in the early exploration/R&D stage; however, coal bed methane(CBM) is produced commercially in the US. CBM is presently being actively explored in India and having matured from the R&D stage, is on a fast track to commercial exploitation.

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