Horizontal wells provide maximum reservoir contact to optimize production rates and recovery. This also holds true for coalbed methane (CBM) drilling. Traditionally, CBM wells have been drilled vertically on a required spacing. Some problems of vertical CBM wells are low gas production rates, partial reserve recovery, high well density and limited surface access. Well density can also have a negative environmental impact.

Advances in horizontal drilling have improved the economics of drilling horizontal CBM wells.

Figure 1. Real-time model of CBM horizontal well drilled with at-bit measurements, LWD resistivity, and forward-modeling software (vertical scale exaggerated). (All figures courtesy of Pathfinder Energy Services)
The direction and position of a horizontal CBM well can be controlled to intersect face cleats and take advantage of directional permeability.

In general, the coal cleat system is orthogonal with one direction cross-cutting the other, impacting the deliverability of coal gas, but it varies from case to case. Most of the methane in coal is adsorbed inside the micropore spaces in the coal. Water contained within the cleats exerts hydrostatic pressure on the adsorbed methane, keeping it from moving out of these micropores into the cleats in the coal.

Whenever reservoir pressure is reduced, the methane desorbs off the coal surfaces, diffuses through the matrix material, and then flows though the cleat system and into the well for delivery to the surface. CBM production depends highly on the properties of the cleat system’s spacing and interconnection.

This dependence on the cleat system promotes drilling horizontal wells in coal. A horizontal well can be positioned perpendicular to the main cleat system of the coal seam and drain significantly larger areas. Horizontal wells in coal provide maximum reservoir contact to optimize production rates and recovery. Recovery and economical results prove that production from these unconventional well configurations is favorable. Using well placement technologies, one can drill in-zone for extended horizontal CBM wells.

The use of at-bit gamma ray and inclination measurements in a logging-while-drilling (LWD) tool string greatly enhances the geosteering capabilities of the bottomhole assembly (BHA). The measurements are made in a short sub positioned immediately above the drill bit. At-bit measurements improve directional control in geosteering complex sections and extend the horizontal section within a particular coal seam.

Geosteering requires software capable of pre-well modeling, displaying the measured information and interactively adapting the model to the real-time data. Offset well data are used with the well plan for a horizontal well to predict the log response of the different logging tools. Different models can be generated to predict what the log response will be when drilling out of zone either at the top or the bottom, or when dramatic facies changes occur. While drilling, the models are continuously updated and compared to the real-time data to improve the formation model and structure. This allows real-time decisions to modify the well path and stay in the intended zone.

At-bit measurements
PathFinder Energy Services has developed the PayZone Inclination and Gamma Ray (PZIG) tool that provides at-bit gamma ray and dynamic inclination measurements from a short
sub directly above the drill bit and enhances the geosteering capabilities of the BHA. For optimal results the tool is run in conjunction with the company’s LWD sensors, PayZone Steering (PZS) software and geosteering specialists. The tool operates as two separate subs. The lower sub contains the sensors for making inclination and gamma ray measurements. Data are transferred from the at-bit sensors in the lower sub to the upper sub via electromagnetic (EM) “short-hop” telemetry. The EM telemetry can transmit up to 60 ft (18.3 m) in 0.5 ohm-m formation. The upper sub receives the data and then transmits the data onto the M/LWD system which then transmits the data to the surface. The upper sub is connected to the M/LWD system which in turn allows the addition of any combination of LWD tools. This design allows the two separate subs to operate with positive displacement motors or 3-D rotary steerables. It is the combination of at-bit inclination and at-bit gamma ray that makes this tool unique. The at-bit gamma ray and inclination sensors are offset 11 in. and 22 in., respectively, from the bit (Figure 1).

The lower sub continuously makes dynamic acquisitions regardless of whether flow is on or off. The gamma ray sensor and tri-axial accelerometers (inclination) are continuously sampled. Communication between the lower and upper sub is bi-directional. The lower sub transmits measured data to the upper sub. The upper sub transmits information for fine tuning communication and timing events in wireless communication between the two subs. Status codes are also transmitted to the surface to allow the field engineer to monitor the communication status between the two subs. The lower and upper subs are both rated to 302°F (150°C) and 20,000 psi.

Well path placement and bit position
The combination of continuous, dynamic inclination and gamma ray at-bit provides the data to determine well path placement and bit position while drilling. By providing immediate lithology and inclination data, the at-bit sensors assist in landing high angle, horizontal wells; determining casing point and optimizing wellbore position. In a horizontal well application, the at-bit inclination allows a smoother well path with reduced tortuosity and dogleg severity by determining the exact build and drop tendencies of the BHA at the bit. By reducing the tortuosity in the well bore, the horizontal section can be drilled to extended lengths due to reduced torque and drag along the well bore. The at-bit inclination measurements can also eliminate vertical uncertainty and allow the true vertical depth (TVD)
to be calculated relative to the zone-of-interest and thus assist in evaluating borehole position. The at-bit gamma ray aids geological positioning by detecting formation changes at the bit. Geosteering becomes more accurate and effective by measuring and recognizing the changing conditions that may affect the well trajectory at the bit.

CBM horizontal well case history
In a recent well (Figure 2), the horizontal CBM well was drilled with at-bit measurements, LWD resistivity, and real-time geosteering. Detailed pre-well modeling was done in addition to real-time modeling while drilling. The model was constructed while drilling.

The coal seam was encountered deeper than expected; however, this was predicted by the
Figure 2. BHA configuration of the bit, lower at-bit sub, mud motor, and upper at-bit sub showing gamma ray and inclination offsets from bit.
onsite geosteering specialist using the forward-modeling software. The landing point of the planned horizontal well was adjusted to enter the coal seam at X475 ft measured depth (MD). The LWD resistivity measurements and forward-modeling software were critical for making the decision to adjust the landing point while drilling. Deep-reading resistivity gave advanced warning that the coal seam would be encountered deeper than expected.

The geosteering model was adjusted to match the real-time, at-bit measurements and LWD resistivity data while drilling. Prior to reaching total depth of the lateral section, the real-time model predicted that the bed dip was changing and would begin to dip steeply upwards. The client chose not to follow the bed dip any further because the achieved horizontal section had already exceeded expectations. The client did want to confirm that the model was correct and drilling continued until the at-bit gamma ray showed that the well had exited the bottom of the coal seam at X695 ft MD. This confirmed the bed dip change predicted by the model. The client determined that the integrated geosteering service was successful in steering the well in zone for 100% of the lateral section.