CBM well drilling and completion

The process of drilling and completing coalbed methane (CBM) wells is similar to wells in conventional reservoirs. Coring, however, can pose special challenges.

Drilling

The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. These data include:

• Reservoir depths and pressures
• Drilling histories
• Environmental considerations

Sources of this information include:

• Regulatory agencies
• Service companies
• Coal-mine operators
• Published literature

After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel.

An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple. For example, water-based drilling fluids may be more damaging to the coals than air or gas drilling, but they are safer in the event of a gas kick, and the damage can be mitigated by fracture stimulation.

CBM wells range in depth from a few hundred meters to more than 3000 m. As a result, several rig types and sizes may be suitable for a given well plan. The most common rig type is the conventional rotary drilling rig, although modified water-well rigs commonly are used to drill shallow coal wells in locations such as the Powder River basin of Wyoming. Other rig types include:

• Top-drive rigs
• Mining rigs
• Coiled-tubing drilling units

In some cases, a drilling rig is used to drill the well to the top of the target coal seams and set/cement casing. A modified completion rig is used to drill the target coals and complete the well while the drilling rig moves to the next well.

The selection of a rig, associated equipment, and drilling fluids is often guided by the completion method. For example, if a dynamic-cavity completion is planned, the rig should be equipped with a power swivel for rotating, reciprocating, and circulating during cleanouts. Auxiliary equipment for this completion will include air compressors and boosters, blowout preventers, a rotating head, and specially designed manifold and flowlines for production testing. In some instances, it is more efficient to select a drilling rig by starting with the desired completion method and designing backwards.

Reservoir pressure and coal characteristics help dictate whether the coal interval is drilled with one of the following:

• Mud
• Water
• Air
• Gas
• Mist

Water-sensitive shales may require the use of gas or air to minimize swelling and sloughing. Slightly underbalanced drilling helps minimize coal formation damage. Horizontally drilled CBM wells are becoming more common and have been used successfully to produce CBM from several locations in the U.S., including the Arkoma basin of Oklahoma and the Appalachian basin of West Virginia. Multilateral wells also are used, especially in coal mining applications to degas coal seams economically ahead of mining.

Coring

Coal cores can be obtained with several different techniques including conventional, wireline, and pressure coring. Conventional coring equipment is drillpipe conveyed, which can result in trip times of an hour or more. Because coal samples begin to desorb gas as they are lifted from the bottom of the well, long trip times can result in large volumes of lost gas. Desorbed gas volumes can be corrected for this effect, but the correction may not provide accurate gas content. As an alternative, many operators use wireline-coring equipment, which can bring samples to the surface in 15 to 20 minutes, significantly reducing lost-gas volumes.

A few operators use pressure coring, which traps the coal downhole in a sealed barrel, preventing any gas loss. This technique requires specialized equipment, which can be difficult to operate, and is approximately five times more expensive than conventional coring. The best applications for pressure coring are those cases in which there are large discrepancies between existing gas content data and well behavior. For example, pressure coring in some San Juan basin wells showed that gas contents were twice as high as those values obtained from conventionally cored wells.

To obtain representative gas content values, high core recoveries are imperative. Unfortunately, recoveries are often low because higher-quality coals tend to be highly cleated and friable, causing them to break up. In addition, many operators wait to core until they see a gas kick on the mud log or a change in the rate of penetration. Waiting until this point means that the top few feet of the coal seam will be missed, and if the coal seam is thin, it may be missed entirely.

Completions

Several different types of CBM completions have been developed to link the wellbore to the cleat system effectively. The most common completion type is to run casing, perforate, and hydraulically fracture the coal seams. Frac jobs in low-permeability coals require long, narrow, propped fractures, whereas short, wide, unpropped fractures are used in higher-permeability coals. If the permeability is high enough and the coals are relatively undamaged by drilling, a simple openhole completion may be sufficient. In a few areas, dynamic-cavity completions are used, resulting in gas rates that are substantially greater than fracture-stimulated wells. Fig. 1 compares fracture-stimulated and dynamic-cavity completion types.

• 

  Fig. 1-Comparison of fracture-stimulated and dynamic cavity completion types.

It is important to stress that optimizing completion methods in a coal reservoir is likely to be a trial-and-error process. This process can be shortened by fully understanding the different completion types available, where they are most applicable, and by collecting sufficient reservoir data to select the best completion. Reviewing publications from the Gas Research Institute (now the Gas Technology Institute), which has been involved in a wide range of CBM completion studies for many years, is a good place to start.

In developing a completion and stimulation procedure, it is useful to begin with a successful stimulation design and modify it to fit a specific coal reservoir. Service companies typically have access to generic designs and an in-house proprietary stimulation model. It is important to conduct this modeling before drilling the well because factors such as stimulation treating pressures, the number of fracture stages, and the expected production rate will have a direct bearing on components such as:

• Rig equipment
• Tubulars
• Overall well cost

Hydraulic fracture stimulation

Hydraulic fracture stimulations in cased and perforated CBM wells are very similar to those in conventional reservoirs, and there are many advantages to this completion type. By casing the well, interbedded strata can be placed behind pipe. This is especially important if the strata include swelling shales or fractured lithologies that could contribute large volumes of water. By perforating coal seams individually, they can be tested to determine their pressure, permeability, and skin before the stimulation treatment.

The well then can be fractured in multiple stages, with treatments optimized for a particular coal seam or group of seams. To ensure the appropriate interval is treated, stages can be isolated with:

• Bridge plugs
• Frac baffles
• Sand plugs

or

• Ball sealers

Limited-entry fracture stimulations may be appropriate if there are several coal zones distributed over a long interval. If there are thin, multiple coals, a modified coiled-tubing unit can be used to treat each coal seam successively, resulting in significant cost savings. During the stimulation, tracers often are added to the fracturing fluids to determine fracture height by running a subsequent gamma ray log. Subsequent well testing can help determine the conductivity of this fracture. During production, fluid-entry surveys can be used to quantify the contribution of individual coal seams.

The biggest disadvantage to fracture stimulation is that productivity is often lower than expected. Horizontal, vertical, or complex fractures may be generated, depending on the depth, seam thickness, and the distribution of in-situ stresses. Induced fractures may be very tortuous, leading to high treatment pressures and early screenouts. Severe formation damage can be caused by coal fines or fracturing fluids. These fracturing fluids can be difficult to remove with gel breakers because of low formation temperatures. Most CBM hydraulic stimulations are performed conventionally through perforations in the casing, although openhole hydraulic stimulations have been tried in several basins. These stimulations typically yield unfavorable results because of poor downhole controls.

CBM fracture-stimulation treatments typically are water based and fall into one of the following four categories:

• Water (slickwater)
• Gel
• Foam
• Proppantless

In a water fracture-stimulation treatment, the base fluid is plain water or water with a high-molecular-weight polyacrylimide polymer added for friction reduction (slickwater). Water fracs are often a preferred treatment because they are less damaging to the coals than gel treatments and are commonly less expensive. Water fracs typically are pumped at high rates of 50 to 80 bbl/min to compensate for the low viscosity and poor sand-carrying capacity of the water. Typical treatments use 12/20- to 20/40-mesh sand with proppant loadings of 2,000 to 3,000 lbm/ft of net coal, ramping up from 1 lbm/gal to 4 to 6 lbm/gal at the end of a typical treatment. One of the main disadvantages of a water frac is the tendency for premature screenouts, which create short fracture half-lengths and result in poorer well performance.

Gelled water-based stimulation fluids use natural or synthetic polymers to provide viscosity and are categorized as linear or cross-linked gels. Their high viscosities result in large transport capacities, which allow bigger jobs to be pumped. Proppant sizes are commonly 12/20- to 20/40-mesh sand with proppant loadings of 5,000 to 10,000 lbm/ft of net coal. The key disadvantage to a gel-based fluid is the potential for serious formation damage caused by cleat blockage from unbroken gel, gel residues, and sorption-induced coal swelling.

Foam treatments are formed by dispersing a gas (usually nitrogen or carbon dioxide) within a water-based fluid. Foam stimulations are commonly used in coal reservoirs with low permeabilities and/or low pressures. When combined with gel systems, foams can provide high viscosities to carry proppant efficiently. An additional benefit of foam is its low hydrostatic pressure, which helps create rapid flowback of the fracturing fluids in low-pressure coals. Disadvantages of foam are:

• The safety concerns of pumping an energized fluid
• Rapid proppant flowback
• The additional cost of the gas

Proppantless stimulations generally use plain water as the base fluid, although gel and foam can be used. When water is used, the volumes and rates are similar to those of a slickwater design. Ball sealers are recommended to ensure effective zonal treatment. Proppantless stimulations are attractive for the following reasons:

• There is no proppant flowback.
• There is no residual-gel damage.
• There are substantial cost savings.

These stimulations are effective in locations such as the Powder River basin of Wyoming, where the objective is to connect the wellbore effectively to high-permeability coals. However, in lower-permeability coals such as the Black Warrior basin of Alabama, production rates indicate that proppantless stimulations are less effective than sand/water stimulations by a ratio of 2:1.

Dynamic-cavity completions

A cavity completion is defined as an openhole completion with an intentionally enlarged wellbore (cavity) in the target coal interval. This completion type was pioneered in the overpressured Fruitland Coal fairway of the San Juan basin, where cavity completions have produced gas and water at rates more than 10 times greater than those of nearby fracture-stimulated wells. Dynamic-cavity completions are created by intentionally causing a large pressure drop in the wellbore, resulting in the redistribution of stresses and subsequent coal failure.¹ Sonar probes run in cavitated wells indicate cavern diameters as large as 8 ft.

Different cavitation techniques have evolved in response to different coal properties and various problems, including:

• The inability to initiate coal failure
• Stuck pipe or tools
• Cavity instability

At least five different types of cavitation are now used including:

• Drilling
• Natural
• Injection
• Mechanical
• Jetting

Each of these operations usually are conducted multiple times over a given coal zone until an acceptable flowrate is obtained. The flow rate following each operation can be determined quickly with a pitot gauge to decide if another cavitation cycle is needed.

Drilling cavitation is performed by drilling through the coal zones in an underbalanced state. This creates a pressure drop across the formation face, causing the coal to shear or break off along near-wellbore cleat or fracture planes. High circulation rates with air, gas, or mist generally are used to clean the hole effectively.

Natural cavitation begins by drilling a targeted coal seam with air, gas, or mist. The bit is then lifted above the seam and the well is shut in. The well builds pressure naturally until a specific pressure is achieved. Buildup surface pressures should be recorded and a curve drawn of each buildup period. Once a pressure breakover point is observed, the well is rapidly opened at the surface with hydraulically operated valves. This causes a high-rate depressurization accompanied by a surge of water, gas, and coal rubble, which are produced up the well and through a flowline to the flare pit. The bit is then lowered to the bottom of the hole while rotating, reciprocating, and circulating. The wellbore is cleaned out and checked for fill, and the operation is repeated until adequate results are achieved. The next zone is then drilled, and the process is repeated. In some cases, all coal zones are drilled before the natural cavitation process is attempted.

Injection cavitation is similar to natural cavitation, except that the wellbore is pressured up from the surface and then surged. The process typically is repeated many times, often for several days or weeks depending on the results of each cycle. Several different fluids can be injected, including the following:

• Gas
• Air
• Water
• CO₂
• Foam
• Coal-comminuting solvents

These are pumped through the drillstring into the formation until a predetermined pressure is reached, sometimes in excess of 1,500 psia. This induced pressure is then suddenly released at the surface by hydraulic valves, resulting in the flow of water, gas, and coal rubble to the surface while continuing to circulate the wellbore through the annulus with gas or air. Because of the large cavities that sometimes are created, a substantial amount of the larger coal pieces may not be circulated out of the wellbore. It is crucial to drill up and clean this fill so that the maximum production potential of the well can be determined.

Mechanical cavitation involves drilling the coal zones to total depth, and then a mechanical hole opener (underreamer) is used to enlarge the wellbore. This process also removes any near-wellbore formation damage. In some cases the noncoal zones above and below the coals are underreamed to relieve overburden stresses that could cause the coals to fail and slough into the wellbore. In some cases, natural or surging cavitation is performed after mechanical cavitation. Jetting cavitation uses hydraulic pressure to direct a jet of gas and water directly toward the coal face. This process may be performed to facilitate a cavity when other cavitation methods have failed. It has been used in several basins with mixed success. In the Piceance basin of the western US, jetting cavitation increased coal gas production from approximately 20 Mscf/D to more than 100 Mscf/D.

Recavitations are performed when the original openhole or cavity completion exhibits poor production compared with offsetting cavitated wells. Additionally, a recavitation or cleanout is performed when the original cavity completion exhibits unexplainable production decline over time. The injection cavitation technique is typically used and the procedure is carried out with a modified completion or cavitation rig. The well is killed with water, and the production casing or liner, if there is one, is removed. The removal is sometimes difficult, resulting in a sidetrack or redrill of the original hole. The well is then recavitated until:

• The flow rate is acceptable
• The cavity is stable
• The amount of produced coal fines is minimal

When a successful cavitation or recavitation operation is performed and the cavity is deemed stable, it is crucial that no additional pressure surges (increasing or decreasing) are applied to the well. When the well is ready for production, it should be opened slowly over a period of several hours to limit the surging of water and gas into the wellbore, thereby minimizing the movement of coal fines and the spalling of coal.

External links

Gas Technology Institute

See also

Coalbed methane

CBM reservoir fundamentals

CBM basin assessment

CBM reservoir evaluation

PEH:Coalbed_Methane

Page champions

George J. Koperna, Jr.