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Results
Determining Microbial Activities in Samples from the Shale Gas Field Compromising Water Reuse and Disposal
Agrawal, A.. (University of Calgary) | Chatterjee, I.. (University of Calgary) | Voordouw, G.. (University of Calgary) | Lomans, B. P. (Shell) | Kuijvenhoven, C.. (Shell) | Henderson, J.. (Baker Hughes)
Abstract Gas production from subsurface shales requires fracture technologies in which fracturing fluid, consisting of guar gum-suspended sand, is forced into the fractures to "prop" them open. The guar gum is easily degraded by bacteria both downhole and at the surface, compromising water reuse or disposal. Samples from the Pinedale shale gas field had high activity of mesophilic acid-producing bacteria (APB), converting guar gum to sugars and then to acetic and propionic acids and of heterotrophic nitrate-reducing bacteria (hNRB), using sugars or acids from guar gum as electron donor for nitrate reduction. Activity of sulfate-reducing bacteria (SRB) was considerably lower with guar gum, reflecting a low initial population size of SRB using the organic acids produced by APB for reduction of sulfate to sulfide. The low concentrations of sulfate in the samples (0–0.4 mM; 0–40 ppm) may be the root cause for this low SRB activity. Indeed, most probable numbers (MPNs) of SRB, determined on standard lactate-sulfate medium were 10- to 100-fold lower than those for APB, determined on standard phenol red-glucose medium. Interestingly, lactate-utilizing SRB appeared to be able to grow in APB medium, indicating that some SRB can also maintain themselves by fermentative metabolism, when sulfate is absent. Culture independent surveys of community composition confirmed that the microbial community at Pinedale samples was dominated by classes of fermentative bacteria (APB). Overall, we conclude that monitoring of the MPN of glucose-fermenting APB most accurately reflects microbial activity and associated biofouling at Pinedale. The success of biocide treatment to reduce microbial activity and associated biofouling is, therefore, also more accurately determined with the APB assay than with that for lactate-utilizing SRB.
- North America > United States (1.00)
- North America > Canada > Alberta (0.49)
- Geology > Mineral > Sulfate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.81)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Reuse (0.60)
Improved Microbial Control Programs for Hydraulic Fracturing Fluids Used During Unconventional Shale-Gas Exploration and Production
Enzien, Michael V. (Dow Microbial Control) | Yin, Bei (Dow Microbial Control) | Love, Donald (Dow Microbial Control) | Harless, Michael (Multi-Chem Production Chemicals) | Corrin, Edward (Multi-Chem Production Chemicals)
Abstract Biocide efficacy studies targeting extended contact times, 7 days, and elevated temperatures, 80° C, led to the discovery of a synergistic combination of Dimethyl Oxazolidine (DMO) and glutaraldehyde. When applied together in specific ratios, most notably a 1:4 ratio of glutaraldehyde to DMO, these two chemistries exhibited superior performance after extended exposure relative to traditional biocide treatments utilizing chemicals such as THPS, glutaraldehyde, and glutaraldehyde/alkyl dimethy benzyl ammonium chloride (ADBAC) blends. The combination of glutaraldehyde and DMO applied in a 1:4 ratio was able to achieve equal performance with lower combined actives. The result of this synergy has a twofold impact on the environmental footprint: it requires less overall biocide for the same level of control, and DMO has a more favorable eco-toxicity profile compared to conventional organic biocides. Field trials on eleven wells and 4 separate well pads in the Marcellus Shale area were treated with the Glutaraldehyde and DMO combination and evaluated using various microbial detection techniques. The benchmark for performance was set by the prior standard chemical treatment in the same shale formation area which utilized the biocide combination, 42.5% active glutaraldehyde and 7.5% active ADBAC blend. Seven wells on three separate well pads treated with Glut/ADBAC were used for comparison to the test wells. The wells treated with the Glut/ADBAC were all dosed at a rate of 300 ppm active ingredient (600ppm product), and the wells used to test the glutaraldehyde/DMO combination treatment were dosed at 200 ppm active (285ppm product). The results of the field trials showed equal or slightly better performance with the combination treatment while utilizing 33% less active chemical, and yielding a reduction of 50% less biocide product applied.
- North America > United States > West Virginia (0.54)
- North America > United States > Pennsylvania (0.54)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
Abstract The practice of slick water fracturing has increased significantly with the advent of horizontal shale stimulation. Many technologies have evolved to improve the practice, including multi-stage fracturing of horizontal wells and simultaneous fracturing, both of which increase frac treatment volumes up to several million gallons of slick water per well. Recent incidents related to interaction of biocides and friction reducers have created concerns for the industry and compelled operators to adopt methods of using biocides with short half-lives, in order to minimize or eliminate biocide contamination in flowbacks reused as frac water. Concurrently, some biocides can crosslink polyacrylamide-based friction reducers, causing severe formation damage, production impairment, and flowbacks that contain cross linked polymers, requiring further chemical treatment and increasing operational costs. This study examines polymers and biocides, along with other additives (oxygen scavengers and scale inhibitors) commonly used in slick water fracturing, and identifies the parameters that could minimize the effectiveness of slick water frac treatments and potentially cause formation damage. To illustrate, this study incorporates a high molecular weight water-based emulsion polyacrylamide as the friction reducer, used in conjunction with various non-oxidizing biocides, with results reflecting positive, negative, or neutral impacts. Experimental results presented in this study are supported by utilizing a 20-gallon capacity friction loop with a Reynolds number of 150,000. Conventional bench top methods were also used. Results indicate that particular biocide-friction reducer systems exhibit significant performance deviations when standard brines or flowback water is used in shale slick water fracturing treatments. Results obtained from this study provide operators a tool to avoid combinations of specific chemicals used in slick water fracturing. Awareness of additive interactions in specific frac fluids used can maximize the effectiveness of treatments, and avoid costly errors that may adversely impair production and jeopardized performance of the biocide. The integrity of the assets on location are thus affected by diminished biocide performance (Olliver et al, 2005). Therefore, any biocide chosen for slick water treatment should be pretested for compatibility with the friction reducers and other chemical additives, in order to insure an incident free operation from a chemical standpoint and minimize the potential for formation damage.
- North America > United States > Pennsylvania (0.28)
- North America > United States > New York (0.28)
- North America > United States > Texas (0.28)
- Geology > Mineral (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Water & Waste Management > Water Management > Constituents > Treated Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.68)
Abstract Effective microbiological control is an important aspect of a successfully executed fracturing job. Control of bacterial growth is often accomplished through the use of biocides such as glutaraldehyde, particularly in the multi-stage, high-volume fracturing of unconventional shale gas reservoirs. Biocidal additives, which are toxic by necessity, can persist in flowback water, so their use in shale fracturing has come under increasing scrutiny since high biocide concentrations in flowback water increase fluid cost and limit the options for disposal. The case for designing a bactericide program to match, and not exceed, the required amount of bacterial control is clear, but rarely is the bacterial load determined during and after the job to verify this balance. Herein, we report a case study undertaken to evaluate the bacterial load of field mix water and flowback water during and after a large hydraulic fracturing job in the Marcellus Shale. A novel oxidative biocide product was used during the fracturing job that has both an effective fast kill and a low toxicity profile (e.g. HMIS rating of 1,0,0). Because of its rapid biodegradability, there was concern that the effective kill of this biocide would not persist beyond a few days. Industry standard techniques (NACE Std. TMO194-94) for quantifying bacteria were applied to water samples taken during the job and over several weeks of production. The biocide was also evaluated for compatibility with common fracturing additives and for its corrosivity to surface equipment and tubular goods. This study determines that the new biocide does not persist in flowback water beyond a few days. However, analysis of flowback water samples reveals that the bacteria count stays low (less than 10 cells/mL) for up to 81 days after application of this biocide in a slickwater fluid. Additionally, genetic fingerprinting using Denaturing Gradient Gel Electrophoresis Analysis (DGGE) was applied to the bacteria in the initial field mix water to allow comparison to any bacteria detected in the flowback samples. This paper will describe the details of this case study. Since the completion of this case study, we have successfully deployed this technology on treatments in the Barnett, Haynesville, Marcellus, and Granite Wash shale regions. This paper reveals details of a field test and of the efficacy of this biocide as tested in flowback waters from the Piceance and Marcellus Shale basin. The results of the bacteria enumerated from each job site sample are presented. Finally, dosage requirements for biocidal efficacy were optimized for slickwater hydraulic fracturing applications are described.
- North America > United States > West Virginia (1.00)
- North America > United States > Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Water & Waste Management > Water Management > Constituents > Treated Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Drilling activity has increased dramatically in unconventional shale gas reservoirs. The drilling fluid of choice in these shale plays is often non-aqueous based fluid (NAF). While NAFs can provide advantages such as shale stabilization, lubricity, and contamination tolerance, environmental consequences and associated costs are an issue. These disadvantages cause operators to seek water-based muds (WBM) for drilling many of these gas reservoirs. Despite some operational similarities, a wide variety of unique downhole conditions can be found in the shale plays. Shale mineralogy and bottomhole temperature represent just two highly variable critical factors in unconventional gas reservoirs. Therefore, a single water-based solution for addressing shale plays globally is not a realistic option. Instead, a customized approach that delivers water-based muds formulated specifically for a given shale play has been pursued. Customization relies on detailed analysis of the well parameters of a given shale play. This analysis includes not only the shale morphology and lithology, but also well drilling program plans, environmental factors and other reservoir-specific considerations. Applying appropriate drilling fluid chemistries based on this detailed analysis has led to the successful field deployment of a number of new shale fluids. Details of the process utilized for customizing a WBM for a shale play, as well as specific examples of new fluids developed for the Barnett, Fayetteville, and Haynesville shales are presented in this paper. Full laboratory development and testing is described. Additionally, field trial results are presented that show specially-designed WBMs can provide comparable performance to NAFs, but with enhanced environmental and economic benefits. Application of the customization process to develop WBMs for other shale plays around the globe is also discussed.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (0.91)
- North America > United States > Arkansas > Washington County > Fayetteville (0.31)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation > Bossier Shale Formation (0.99)
- (9 more...)
Abstract This paper concerns the development and implementation of a replacement chemistry for 2-butoxyethanol used in fracturing. The new product was synthesized to provide mutual solvency, wettability modification and clay swelling inhibition. Recently, 2-butoxyethanol has come under scrutiny in North America (e.g. prompting Environment and Health Canada to add it to Schedule 1 of the Canadian Environmental Protection Act). Precautions need to be taken when working with 2-butoxyethanol due to toxicity concerns. Exposure to high levels has led to reported nose and eye irritation, headaches and vomiting. Introduction of an alternate product has had a profound effect on the stimulation market in Canada. So far, 400,000 kg of the alternative product has replaced an estimated annual usage total of 3 to 4 million kg of 2- butoxyethanol. The new product also has had successful applications in the US, Latin America and Europe. There has been a significant environmental impact already realized through the use of this alternative product, and there is even greater unrealized potential. Additionally, as a non-regulated product for use and handling, the safety and material handling implications are greatly improved. This paper details the chemistry of the replacement product, as well as environmental information to support the use of this product as a benign replacement for 2-butoxyethanol. An in-depth description of the laboratory testing used to identify, evaluate and select the appropriate treatment parameters also is given. The paper concludes with two case histories from northeast Alberta where this product was successfully used as part of a fracture treatment for long, horizontal, multi-zone shale gas plays. Furthermore comparisons are made using 2-butoxyethanol and no mutual solvent chemistry in a fracture treatment. This data shows the clear benefit of using this new chemistry.
- North America > United States > Texas (0.94)
- North America > Canada > British Columbia (0.70)
- North America > Canada > Alberta (0.68)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (4 more...)
Summary This paper presents a discussion of fractured-horizontal-well performance in millidarcy permeability (conventional) and micro- to nanodarcy permeability (unconventional) reservoirs. It provides interpretations of the reasons to fracture horizontal wells in both types of formations. The objective of the paper is to highlight the special productivity features of unconventional shale reservoirs. By using a trilinear-flow model, it is shown that the drainage volume of a multiple-fractured horizontal well in a shale reservoir is limited to the inner reservoir between the fractures. Unlike conventional reservoirs, high reservoir permeability and high hydraulic-fracture conductivity may not warrant favorable productivity in shale reservoirs. An efficient way to improve the productivity of ultratight shale formations is to increase the density of natural fractures. High natural-fracture conductivities may not necessarily contribute to productivity either. Decreasing hydraulic-fracture spacing increases the productivity of the well, but the incremental production gain for each additional hydraulic fracture decreases. The trilinear-flow model presented in this work and the information derived from it should help the design and performance prediction of multiple-fractured horizontal wells in shale reservoirs.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Overton Field (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.89)
- (5 more...)
Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition held in The Woodlands, Texas, USA, 5-6 April 2011. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract In shale gas horizontal wells with multiple intervals completed, the predominant completions method has been multistage fracturing while plugging with drillable bridge plugs and jet perforating the cemented casing. Typically the bridge plugs are drilled out under pressure with coiled tubing. The ability to optimize drilling/milling parameters while drilling out with pressurized coiled tubing has been hampered by the lack of information in the coiled tubing cab about the speed that debris is generated, the size of debris generated, and whether the circulation fluid properties and rate are sufficient to remove the debris from the hole.
- North America > Canada (0.69)
- North America > United States > Texas > Montgomery County > The Woodlands (0.24)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
Abstract Treatment isolation using composite bridge plugs (CP) has been practiced for about 18 years in North America and continues to be among the most economical ways to stimulate horizontal and multi-layer vertical wells. Despite this long experience, many end users still experience problems in these applications because of sub-optimal choices regarding product selection, run-in and removal options, and unrealistic expectations regarding plug life in downhole environments. This paper will identify best practices for using CPs, based on prior technical papers, field experience, and manufacturers' published data. These practices maximize the chances of successfully installing and removing CPs in multi-zone treatment applications, improving the economics of oil and gas plays requiring multiple stimulation treatments per well. As multi-zone completion activity increases in regions outside of North America, treatment applications using CPs will also increase in those regions. Realizing the benefits of using CPs in emerging regions will be achieved by learning about best practices from regions with extensive experience in their use.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- Oceania > Australia > Northern Territory > McArthur Basin > Beetaloo Basin (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.94)
- (12 more...)
Technology Focus The 2009 reserves of natural gas were approximately equivalent to 82% of the oil reserves, yet gas consumption was only approximately one-fifth of oil consumption. With its relative abundance, clearly, natural gas will continue as an important energy source for some time, as emphasized by the current focus on unconventional gas sources, such as coalbed methane (CBM), shale gas, tight gas, and even potential hydrate production. Even conventional large offshore reserves are developed more economically by use of floating liquefied-natural-gas (LNG) compression instead of onshore compression and very long subsea pipelines. Water handling and reuse is key to the future of the CBM industry, which is progressing toward LNG export. There are shale-gas workshops in Palos Verdes, California (11–12 April) and in Beijing (29 May–1 June) and an unconventional-gas workshop in Sapporo, Hokkaido, Japan (10–14 July). SPE has an Unconventional Reservoir Technical Interest Group (TIG), which is a useful information exchange, as is the Gas Technology TIG. Other key high-volume gas sources that are only now able to be more fully exploited include highly-sour-gas production, which has many challenges in hydrate inhibition and sour-gas removal. There is a Forum on sour gas in Bali (8–13 May). Much research has gone into low-dose kinetic hydrate inhibition in the last decade, and the next phase will be recovery and reuse of the valuable inhibitors. The 2011 SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas (11–13 April) highlights progress in gas-processing-chemical applications. Natural Gas Processing and Handling additional reading available at OnePetro: www.onepetro.org SPE 131160 “The Use of Huff-‘n’-Puff Method in a Single Horizontal Well in Gas Production From Marine Gas-Hydrate Deposits in the Shenhu Area of the South China Sea” by Gang Li, Key Laboratory of Renewable Energy and Gas Hydrate, et al. SPE 133975 “CO2 Storage in Saline Aquifers: Design of a Demonstration Project To Dispose of CO2 Associated with Natural-Gas Fields in the South China Sea” by L. Zhang, SPE, China University of Petroleum (East China), et al. SPE 131663 “Hydrate Formation: Considering the Effects of Pressure, Temperature, Composition, and Water” by J. Rajnauth, SPE, Texas A&M University, et al.
- North America > United States > Texas > Montgomery County > The Woodlands (0.26)
- Asia > Japan > Hokkaidō > Hokkaidō Prefecture > Sapporo (0.26)
- Asia > China > Beijing > Beijing (0.26)