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In general shale is thought to be relatively nonreactive to low pH or acidic fluids. This is because of the general belief the clay, silt, and organic materials comprising the major components of shale formations exhibit insignificant bulk solubility in acid. What we find however is that shale units are highly laminated and contain acid-soluble minerals homogenized in the shale bulk matrix and natural fractures. XRD analysis and SEM images of shale samples show a great diversity and distribution of soluble material in the shale producing unit. SEM images of the shale fracture face before and after exposure to certain reactive fluids show a remarkable amount of surface texture disruption and micro-etching of the fractured surface. Based on these observations, it is concluded that reactive fluids are capable of (1) enhancing gas diffusion into and through narrow-aperture induced fractures, and (2) increasing surface area for flow of gas from the shale matrix. Such fluids are also capable of enhancing flow through mineral-filled microcracks or other secondary porosity. Initial production response from wells treated with reactive low pH fluids has been promising. This paper documents X-ray and SEM analyses of many shale plays in Oklahoma. Production enhancement mechanisms are proposed to explain the observed physical effects of these fluids on shale.

Summary Application of citric acid for damage removal in both clastic and carbonate rocks has historically not received widespread acceptance because of formation damage concerns regarding precipitation of calcium citrate. In addition, usage of citric acid in place of hydrochloric acid has been avoided because of lower bulk carbonate dissolving power relative to hydrochloric acid. However, environmental, safety, and corrosion concerns with using hydrochloric acid have sparked renewed interest in citric acid for stimulation. This paper reconsiders the use of citric acid as both an additive to conventional hydrochloric acid systems and as a stand-alone acidizing fluid. The paper reviews extensive laboratory work focused on understanding reaction pathways and geochemical precipitation issues, and it takes a new look at paradigms related to the calcium citrate issue. Laboratory studies performed independently by two research laboratories address two main areas of investigation: (1) Evaluation of potential geochemical reaction paths and precipitation of calcium citrate and (2) mechanisms for generation of preferential etching in two carbonate rock lithotypes. The described mechanism for etching enhances conductivity in a contrasting mode compared to hydrochloric acid. Findings based on this work provide new insights into the applications, usage, and potential limitations of citric acid. A newly proposed process for downhole reaction is presented. This process differs greatly from long-held paradigms built on a foundation of bench-top experimentation. Factors controlling downhole reactions are disclosed, and the results of core testing and fracture conductivity experiments are presented.

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 laboratory studies and field testing that demonstrate how surface modification of proppant with polymeric "tackifiers" can improve the fluid conductivity of propped hydraulic fractures. It also identifies and describes several conductivity enhancement mechanisms that result from proppant-surface modification. Molecular simulations identified optimal intermolecular friction factors of the polymeric "tackifiers" that increases the proppant's intergranular friction. Once coated with a tacky surface-modification material, the proppant grain interacts instantaneously with the surrounding particulates resulting in a stabilized proppant bed. Experiments show that coating the proppant with these tacky polymeric materials hinders proppant settling in aqueous-based fracturing fluid; this characteristic results in better vertical distribution of proppant within the fracture and an increase in pack porosity. Conductivity measurements of proppant packs [in accordance with American Petroleum Institute (API) standards] support this observation and reveal the influence that closure stress plays in the final proppant-pack conductivity. Testing with a complete fracturing fluid system indicates that improved fluid removal is possible under certain conditions. Extensive field testing supports this conclusion by providing evidence of increased and sustained fracture productivity with faster and more effective well cleanup after water-based fracturing treatments. Because the proppant surface is modified on the fly and requires no additional time for curing, aggressive gel-break schedules and well flowback rates are used. The use of tacky, polymeric surface-modification materials stabilized proppant packs resulting in little or no backproduction of proppant or fines. This paper includes treatment results from formations that were hydraulically fractured with one of these surface-modification agents.

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.

The dewatering process, which stimulates gas desorption, is essential for gas production in coalbed methane (CBM) reservoirs. Many CBM wells require hydraulic fracturing to provide interconnectivity and hydraulic access to the cleat/matrix system. Without hydraulic communication and access to the hierar-chical flowpath, gas desorption is severely limited or nonexistent. When economics allow operators to continue long-term gas production, the gas rate of most coalbed wells will eventually increase. Over time, gas desorbs from the coal macerals that form the cleat blocks. However, some coalbed fields experience premature or severe declines in production because of poor hydraulic-fracture conductivity. Particulates have been discovered as a primary cause of poor hydraulic-fracture conductivity. These particulates flow with produced water; they are then deposited within the proppant pack where they block pore throats and interfere with gas desorption. A surface modification agent (SMA) that prevents or reduces hydraulic-fracture conductivity damage has been developed and successfully field-tested. This agent, which has strong adhesive properties, helps delay or prevent conductivity damage to the proppant bed. This paper discusses (1) the problems associated with poor hydraulic-fracture conductivity, (2) why it occurs in coalbed wells, and (3) how a new SMA can minimize the problem.

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.