J. Alexandra Hakala

Trace Metal Source Terms in Carbon Sequestration Environments

Carbon dioxide sequestration in deep saline and depleted oil geologic formations is feasible and promising; however, possible CO(2) or CO(2)-saturated brine leakage to overlying aquifers may pose environmental and health impacts. The purpose of this study was to experimentally define a range of concentrations that can be used as the trace element source term for reservoirs and leakage pathways in risk simulations. Storage source terms for trace metals are needed to evaluate the impact of brines leaking into overlying drinking water aquifers. The trace metal release was measured from cements and sandstones, shales, carbonates, evaporites, and basalts from the Frio, In Salah, Illinois Basin, Decatur, Lower Tuscaloosa, Weyburn-Midale, Bass Islands, and Grand Ronde carbon sequestration geologic formations. Trace metal dissolution was tracked by measuring solution concentrations over time under conditions (e.g., pressures, temperatures, and initial brine compositions) specific to the sequestration projects. Existing metrics for maximum contaminant levels (MCLs) for drinking water as defined by the U.S. Environmental Protection Agency (U.S. EPA) were used to categorize the relative significance of metal concentration changes in storage environments because of the presence of CO(2). Results indicate that Cr and Pb released from sandstone reservoir and shale cap rocks exceed the MCLs by an order of magnitude, while Cd and Cu were at or below drinking water thresholds. In carbonate reservoirs As exceeds the MCLs by an order of magnitude, while Cd, Cu, and Pb were at or below drinking water standards. Results from this study can be used as a reasonable estimate of the trace element source term for reservoirs and leakage pathways in risk simulations to further evaluate the impact of leakage on groundwater quality.

High throughput method for Sr extraction from variable matrix waters and 87Sr/86Sr isotope analysis by MC-ICP-MS

Natural isotope tracers, such as strontium (Sr), can facilitate the tracking of brine migration caused by CO2 injection in carbon storage sites and assist in identifying the origin of formation waters associated with oil and gas exploration. However, it might be necessary to analyze tens of samples with complex chemical compositions over a short period to identify subsurface reactions and respond to unexpected fluid movement in the host formation. These conditions require streamlined Sr separation chemistry for samples ranging from pristine groundwaters to those containing high total dissolved solids, followed by rapid measurement of isotope ratios with high analytical precision. Here we describe a method useful for the separation of Sr from energy related geofluids and the rapid measurements of Sr isotopic ratios by MC-ICP-MS. Existing vacuum-assisted Sr separation procedures were modified by using inexpensive disposable parts that also eliminate cross contamination. These improvements will allow an operator to independently prepare samples for Sr isotope analysis using fast, low cost separation procedures and commercially available components. We optimized the elution chemistry by adjusting acid normality and elution rates to provide better separation of Sr from problematic matrices (e.g. Rb, Ca, Ba, K) associated with oilfield brines and formation waters. The separation procedure is designed for high sample throughputs that are ready for immediate Sr isotope measurements by MC-ICP-MS. Precise Sr isotope results can be achieved by MC-ICP-MS with a throughput of 4 to 5 samples per hour. Fluids from a range of geologic environments analyzed by this method yielded results within the analytical uncertainty of 87Sr/86Sr ratios previously determined by standard column separation and TIMS. This method provides a fast and effective way to use isolate Sr in a variety of geologic fluids for isotopic analysis by MC-ICP-MS.

Rare earth element geochemistry of outcrop and core samples from the Marcellus Shale.

In this work, the geochemistry of the rare earth elements (REE) was studied in eleven outcrop samples and six, depth-interval samples of a core from the Marcellus Shale. The REE are classically applied analytes for investigating depositional environments and inferring geochemical processes, making them of interest as potential, naturally occurring indicators of fluid sources as well as indicators of geochemical processes in solid waste disposal. However, little is known of the REE occurrence in the Marcellus Shale or its produced waters, and this study represents one of the first, thorough characterizations of the REE in the Marcellus Shale. In these samples, the abundance of REE and the fractionation of REE profiles were correlated with different mineral components of the shale. Namely, samples with a larger clay component were inferred to have higher absolute concentrations of REE but have less distinctive patterns. Conversely, samples with larger carbonate fractions exhibited a greater degree of fractionation, albeit with lower total abundance. Further study is necessary to determine release mechanisms, as well as REE fate-and-transport, however these results have implications for future brine and solid waste management applications.

Mineral Reactions in Shale Gas Reservoirs: Barite Scale Formation from Reusing Produced Water As Hydraulic Fracturing Fluid

Hydraulic fracturing for gas production is now ubiquitous in shale plays, but relatively little is known about shale-hydraulic fracturing fluid (HFF) reactions within the reservoir. To investigate reactions during the shut-in period of hydraulic fracturing, experiments were conducted flowing different HFFs through fractured Marcellus shale cores at reservoir temperature and pressure (66 °C, 20 MPa) for one week. Results indicate HFFs with hydrochloric acid cause substantial dissolution of carbonate minerals, as expected, increasing effective fracture volume (fracture volume + near-fracture matrix porosity) by 56-65%. HFFs with reused produced water composition cause precipitation of secondary minerals, particularly barite, decreasing effective fracture volume by 1-3%. Barite precipitation occurs despite the presence of antiscalants in experiments with and without shale contact and is driven in part by addition of dissolved sulfate from the decomposition of persulfate breakers in HFF at reservoir conditions. The overall effect of mineral changes on the reservoir has yet to be quantified, but the significant amount of barite scale formed by HFFs with reused produced water composition could reduce effective fracture volume. Further study is required to extrapolate experimental results to reservoir-scale and to explore the effect that mineral changes from HFF interaction with shale might have on gas production.

Hydraulic Fracturing and Organic Compounds - Uses, Disposal and Challenges

Hydraulic fracturing has allowed oil and natural gas producers in the U.S. to effectively tap reservoirs that would otherwise be unfeasible to produce. In recent years, the natural gas industry has experienced a boost in production through the increased use of hydraulic fracturing in shale and tight sand formations. Despite its production advantages, the hydraulic fracturing process is not without its concerns. Hydraulic fracturing utilizes large quantities of water which, together with a number of chemical additives known as the ‘fracturing fluid’, are injected into underground formations. After being injected, between 5 and 60 percent of this fluid mixture flows back to the surface as produced water carrying with it any remaining chemical additives and naturally occurring material from the formation. Due to the complicated cycling of water and organic compounds during hydraulic fracturing and produced water treatment, the ability to independently identify and quantify chemicals associated with fracturing activities at different stages of the shale gas water lifecycle remains challenging. The ability to identify and quantify organics may be relevant both for maximizing efficiency during fracturing and water treatment, and for environmental management. Continued analyses of both the ‘hydraulic fracturing fluid’ and the produced water have shown that not all organic compounds that were injected into the well return to the surface. This suggests that adsorption/desorption and/or chemical transformation processes are taking place within the formation. Determination whether organic compounds detected in produced waters are synthetic or naturally-derived from the reservoir is complicated by the number of compounds that exist both naturally in the formation, and are injected with the hydraulic fracturing fluid. Depending on the fracturing job, roughly 4 – 10 different synthetic organic compounds are added to the hydraulic fracturing fluid at one time. A survey of 1000 API registered wells hydraulically fractured in Western Pennsylvania and West Virginia showed roughly 150 different organic compounds used as ingredients in the fracturing fluids. This makes identification and analysis of these compounds in produced waters difficult. Further complications for evaluating organics in the shale gas water life cycle stem from the use of recycled produced waters. Analysis of samples from produced water treatment facilities showed the presence of organic compounds in the inlet and effluent of the treatment facility. The effluent of many treatment plants is reused bringing with it the organic compounds that are still present to the next hydraulic fracture job. This paper looks into the different organic compounds used in the hydraulic fracturing process, their possible life-cycle after the process, the difficulties encountered when analyzing for these compounds, and possible challenges with site planning and environmental decision-making. Introduction Clean energy, energy independence and security have been the key issues regarding energy demands in the United States. In 2008, it was reported that natural gas, coal and oil supply about 85% of the nation’s energy (US DOE 2009b; EIA 2008). Natural gas itself supplied about 22% of the U.S. energy needs in 2008 and 25% by 2011 (Rahm 2011; EIA 2008; EIA 2012). Most of the US natural gas reserves are present in tight sands, shale and coal beds and less in conventional wells (Arthur et al. 2009; Soeder 2012). Shale formations have low permeability and require stimulation in order to produce enough natural gas to be economically feasible (Arthur el al. 2010; Rahm 2011; Suarez 2012). Although the process of hydraulic fracturing has been around for over 60 years (Rahm 2011), the recent advancements in horizontal drilling coupled with advanced completion technologies have allowed oil and natural gas producers in the U.S. to effectively tap reservoirs that would be impractical and inefficient to produce (Nicot and Scanlon 2012; Suarez 2012). The advancements have led to a boost in production of natural gas through