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The early stages of a coalbed methane (CBM) project development often require more extensive use of currently available technologies than can be economically justified when approached from a conventional oil and gas drilling focus. As a result, key evaluation tools and technologies are either omitted or not considered before significant decisions are made regarding viability of a CBM play. Understanding that the various lifecycle phases will each affect different objectives and decision points is important. Following site acquisition and estimating basic drilling costs, at least five lifecycle phases can be identified: (1) Regional Resource Reconnaissance, (2) Local Asset Evaluation, (3) Early Development, (4) Mature Development; and (5) Declining Production. A systematic review of current and recently developed enabling technologies is presented in the context of their potential use and applicability. Environmental risk and other constraints that can impact development vary globally, as do economics and production forecasting. New and emerging chemical technologies, as well as hydraulic fracturing refinements, play key roles in various lifecycle phases and decision making to identify successful CBM development projects as early as possible. The paper presents strategies that can reduce development phase failure risk and help predict or rank production potential. Economic constraints usually become more restrictive as the lifecycle moves to Phase 4 and beyond, but key information needed to enter Phase 4 is often overlooked. Examples of this scenario are presented from a global perspective. Globally, new and existing technologies combined with dynamic gas and electricity markets are changing the nature of CBM development opportunities. More accurate and timely go/no-go information needs to be used in the decision making process. Converting development opportunities to develop-ment successes involves integrating planning and evaluation methods, using targeted development technologies in the proper phase, and managing risk.

Results of recent field trials with a newly developed fracturing-fluid system and liquid surface-modification additive for coating proppant are presented in this paper. The work was performed in the Underpressured Fruitland Coal (UFTC) gas reservoir in the Northern San Juan Basin of Colorado and New Mexico. This new technology has influenced production in the region. Data of the test-well population are compared to the coal gas and water production from the reservoir. This study identifies and applies the new fracturing system technology for improving production. The results of this study provide information that may apply to other coal-gas reservoirs. The study group of wells uses hydraulic fracturing treatments consisting of a new low polymer loading crosslinked fluid system with a proppant surface-modification additive. The fluid system has increased crosslinked-fluid viscosity, requiring a lower gelling-agent concentration. A liquid additive that coats the proppant and increases its surface adhesion is added in the blender tub during the treatment. The surface friction between the coated proppant grains resists high flow rates during cleanup. Modifying the proppant also influences the migration behavior and blocking effects of fines (coal and precipitates) within the propped fracture.

This paper describes a new diagnostic process that can be applied to gas-storage wells. This technique consists of identifying damage mechanisms and designing individual treatments for each mechanism. The damage identification portion of the new process involves integrating (1) borehole imaging, (2) downhole sampling, (3) well testing, (4) laboratory analyses, (5) reservoir evaluation, and (6) reviews of well and field histories. This part of the process is partially based on results from a previous formation-damage identification study funded by the Gas Research Institute (GRI).1 Two case studies are provided. Based on overall economic results, field deliverability enhancement projects featuring the new diagnostic process have greater gas deliverability potential than conventionally treated wells. The two case studies presented were performed in porous-media gas-storage fields. Case Study 1 (Page 3) was performed on a pressure-drive carbonate reservoir. Case Study 2 (Page 4) was performed on a water-drive clastic reservoir.

A new proppant-pack technology is enhancing incremental gas recovery and estimated ultimate recovery (EUR) of unconventional methane gas in the Northern Michigan Antrim production area. This new technology has enhanced project economics in both restimulation and new-drill applications. Over time, these new technology applications that have evolved in the Antrim play, have resulted in investment-capital infusion and have encouraged development, which has capitalized on development strategies that implement new technology. The new proppant-pack technology uses a liquid surface-modification agent (SMA) that is applied to proppant on-the-fly during a hydraulic fracture-stimulation treatment. This process coats individual proppant grains with a "tacky" surface, causing the proppant grains to cluster and create a network of loosely packed grains with interconnected clusters. The result is a pliable, but consolidated, proppant pack. The proppant pack also contains conduits, but its adhesive nature increases proppant resistance to post-fracture migration toward the wellbore. The modified proppant grain surfaces enhance the dewatering process by promoting the flow of aqueous fluids and entrapping potentially damaging fines on grain surfaces rather than in pore constrictions. This paper compares SMA restimulation technology to newly drilled wells on a project basis. Production enhancement results (based on individual well response and impact on total project production response) show that production results are important at both the project and individual well scale. When compared to the population of conventionally treated wells, newly drilled completions that received the new SMA technology modified the probability distribution of well production. Restimulation was economical on a payout basis and converted gas-in-place to recoverable reserves, enhancing the economics of lower production-class wells.