Jean-Philippe Nicot

Water Use for Shale-Gas Production in Texas, U.S.

Shale-gas production using hydraulic fracturing of mostly horizontal wells has led to considerable controversy over water-resource and environmental impacts. The study objective was to quantify net water use for shale-gas production using data from Texas, which is the dominant producer of shale gas in the U.S. with a focus on three major plays: the Barnett Shale (~15,000 wells, mid-2011), Texas-Haynesville Shale (390 wells), and Eagle Ford Shale (1040 wells). Past water use was estimated from well-completion data, and future water use was extrapolated from past water use constrained by shale-gas resources. Cumulative water use in the Barnett totaled 145 Mm(3) (2000-mid-2011). Annual water use represents ~9% of water use in Dallas (population 1.3 million). Water use in younger (2008-mid-2011) plays, although less (6.5 Mm(3) Texas-Haynesville, 18 Mm(3) Eagle Ford), is increasing rapidly. Water use for shale gas is <1% of statewide water withdrawals; however, local impacts vary with water availability and competing demands. Projections of cumulative net water use during the next 50 years in all shale plays total ~4350 Mm(3), peaking at 145 Mm(3) in the mid-2020s and decreasing to 23 Mm(3) in 2060. Current freshwater use may shift to brackish water to reduce competition with other users.

Comparison of Water Use for Hydraulic Fracturing for Unconventional Oil and Gas versus Conventional Oil

We compared water use for hydraulic fracturing (HF) for oil versus gas production within the Eagle Ford shale. We then compared HF water use for Eagle Ford oil with Bakken oil, both plays accounting for two-thirds of U.S. unconventional oil production in 2013. In the Eagle Ford, we found similar average water use in oil and gas zones per well (4.7-4.9 × 10(6) gallons [gal]/well). However, about twice as much water is used per unit of energy (water-to-oil ratio, WOR, vol water/vol oil) in the oil zone (WOR: 1.4) as in the gas zone (water-to-oil-equivalent-ratio, WOER: 0.6). We also found large differences in water use for oil between the two plays, with mean Bakken water use/well (2.0 × 10(6) gal/well) about half that in the Eagle Ford, and a third per energy unit. We attribute these variations mostly to geological differences. Water-to-oil ratios for these plays (0.6-1.4) will further decrease (0.2-0.4) based on estimated ultimate oil recovery of wells. These unconventional water-to-oil ratios (0.2-1.4) are within the lower range of those for U.S. conventional oil production (WOR: 0.1-5). Therefore, the U.S. is using more water because HF has expanded oil production, not because HF is using more water per unit of oil production.

Source and fate of hydraulic fracturing water in the barnett shale: A historical perspective

Considerable controversy continues about water availability for and potential impacts of hydraulic fracturing (HF) of hydrocarbon assets on water resources. Our objective was to quantify HF water volume in terms of source, reuse, and disposal, using the Barnett Shale in Texas as a case study. Data were obtained from commercial and state databases, river authorities, groundwater conservation districts, and operators. Cumulative water use from ∼ 18,000 (mostly horizontal) wells since 1981 through 2012 totaled ∼ 170,000 AF (210 Mm(3)); ∼ 26 000 AF (32 Mm(3)) in 2011, representing 32% of Texas HF water use and ∼ 0.2% of 2011 state water consumption. Increase in water use per well by 60% (from 3 to 5 Mgal/well; 0.011-0.019 Mm(3)) since the mid-2000s reflects the near-doubling of horizontal-well lengths (2000-3800 ft), offset by a reduction in water-use intensity by 40% (2000-1200 gal/ft; 2.5-1.5 m(3)/m). Water sources include fresh surface water and groundwater in approximately equal amounts. Produced water amount is inversely related to gas production, exceeds HF water volume, and is mostly disposed in injection wells. Understanding the historical evolution of water use in the longest-producing shale play is invaluable for assessing its water footprint for energy production.

Certification Framework Based on Effective Trapping for Geologic Carbon Sequestration

We have developed a certification framework (CF) for certifying the safety and effectiveness of geologic carbon sequestration (GCS) sites. Safety and effectiveness are achieved if CO{sub 2} and displaced brine have no significant impact on humans, other living things, resources, or the environment. In the CF, we relate effective trapping to CO{sub 2} leakage risk which takes into account both the impact and probability of leakage. We achieve simplicity in the CF by using (1) wells and faults as the potential leakage pathways, (2) compartments to represent environmental resources that may be impacted by leakage, (3) CO{sub 2} fluxes and concentrations in the compartments as proxies for impact to vulnerable entities, (4) broad ranges of storage formation properties to generate a catalog of simulated plume movements, and (5) probabilities of intersection of the CO{sub 2} plume with the conduits and compartments. We demonstrate the approach on a hypothetical GCS site in a Texas Gulf Coast saline formation. Through its generality and flexibility, the CF can contribute to the assessment of risk of CO{sub 2} and brine leakage as part of the certification process for licensing and permitting of GCS sites around the world regardless of the specific regulations in place in any given country.

Will water scarcity in semiarid regions limit hydraulic fracturing of shale plays

There is increasing concern about water constraints limiting oil and gas production using hydraulic fracturing (HF) in shale plays, particularly in semiarid regions and during droughts. Here we evaluate HF vulnerability by comparing HF water demand with supply in the semiarid Texas Eagle Ford play, the largest shale oil producer globally. Current HF water demand (18 billion gallons, bgal; 68 billion liters, bL in 2013) equates to ~16% of total water consumption in the play area. Projected HF water demand of ~330 bgal with ~62 000 additional wells over the next 20 years equates to ~10% of historic groundwater depletion from regional irrigation. Estimated potential freshwater supplies include ~1000 bgal over 20 yr from recharge and ~10 000 bgal from aquifer storage, with land-owner lease agreements often stipulating purchase of freshwater. However, pumpage has resulted in excessive drawdown locally with estimated declines of ~100–200 ft in ~6% of the western play area since HF began in 2009–2013. Non-freshwater sources include initial flowback water, which is ≤5% of HF water demand, limiting reuse/recycling. Operators report shifting to brackish groundwater with estimated groundwater storage of 80 000 bgal. Comparison with other semiarid plays indicates increasing brackish groundwater and produced water use in the Permian Basin and large surface water inputs from the Missouri River in the Bakken play. The variety of water sources in semiarid regions, with projected HF water demand representing ~3% of fresh and ~1% of brackish water storage in the Eagle Ford footprint indicates that, with appropriate management, water availability should not physically limit future shale energy production.

Finding regional co-location patterns for sets of continuous variables in spatial datasets

This paper proposes a novel framework for mining regional co-location patterns with respect to sets of continuous variables in spatial datasets. The goal is to identify regions in which multiple continuous variables with values from the wings of their statistical distribution are co-located. A co-location mining framework is introduced that operates in the continuous domain and which views regional co-location mining as a clustering problem in which an externally given fitness function has to be maximized. Interestingness of co-location patterns is assessed using products of z-scores of the relevant continuous variables. The proposed framework is evaluated by a domain expert in a case study that analyzes Arsenic contamination in Texas water wells centering on regional co-location patterns. Our approach is able to identify known and unknown regional co-location patterns, and different sets of algorithm parameters lead to the characterization of Arsenic distribution at different scales. Moreover, inconsistent colocation sets are found for regions in South Texas and West Texas that can be clearly attributed to geological differences in the two regions, emphasizing the need for regional co-location mining techniques. Moreover, a novel, prototype-based region discovery algorithm named CLEVER is introduced that uses randomized hill climbing, and searches a variable number of clusters and larger neighborhood sizes.

Unconventional oil and gas spills: Materials, volumes, and risks to surface waters in four states of the U.S.

Extraction of oil and gas from unconventional sources, such as shale, has dramatically increased over the past ten years, raising the potential for spills or releases of chemicals, waste materials, and oil and gas. We analyzed spill data associated with unconventional wells from Colorado, New Mexico, North Dakota and Pennsylvania from 2005 to 2014, where we defined unconventional wells as horizontally drilled into an unconventional formation. We identified materials spilled by state and for each material we summarized frequency, volumes and spill rates. We evaluated the environmental risk of spills by calculating distance to the nearest stream and compared these distances to existing setback regulations. Finally, we summarized relative importance to drinking water in watersheds where spills occurred. Across all four states, we identified 21,300 unconventional wells and 6622 reported spills. The number of horizontal well bores increased sharply beginning in the late 2000s; spill rates also increased for all states except PA where the rate initially increased, reached a maximum in 2009 and then decreased. Wastewater, crude oil, drilling waste, and hydraulic fracturing fluid were the materials most often spilled; spilled volumes of these materials largely ranged from 100 to 10,000L. Across all states, the average distance of spills to a stream was highest in New Mexico (1379m), followed by Colorado (747m), North Dakota (598m) and then Pennsylvania (268m), and 7.0, 13.3, and 20.4% of spills occurred within existing surface water setback regulations of 30.5, 61.0, and 91.4m, respectively. Pennsylvania spills occurred in watersheds with a higher relative importance to drinking water than the other three states. Results from this study can inform risk assessments by providing improved input parameters on volume and rates of materials spilled, and guide regulations and the management policy of spills.

Unconventional Oil and Gas Spills: Risks, Mitigation Priorities, and State Reporting Requirements

Rapid growth in unconventional oil and gas (UOG) has produced jobs, revenue, and energy, but also concerns over spills and environmental risks. We assessed spill data from 2005 to 2014 at 31 481 UOG wells in Colorado, New Mexico, North Dakota, and Pennsylvania. We found 2-16% of wells reported a spill each year. Median spill volumes ranged from 0.5 m3 in Pennsylvania to 4.9 m3 in New Mexico; the largest spills exceeded 100 m3. Seventy-five to 94% of spills occurred within the first three years of well life when wells were drilled, completed, and had their largest production volumes. Across all four states, 50% of spills were related to storage and moving fluids via flowlines. Reporting rates varied by state, affecting spill rates and requiring extensive time and effort getting data into a usable format. Enhanced and standardized regulatory requirements for reporting spills could improve the accuracy and speed of analyses to identify and prevent spill risks and mitigate potential environmental damage. Transparency for data sharing and analysis will be increasingly important as UOG development expands. We designed an interactive spills data visualization tool ( http://snappartnership.net/groups/hydraulic-fracturing/webapp/spills.html ) to illustrate the value of having standardized, public data.

A framework for regional association rule mining and scoping in spatial datasets

The motivation for regional association rule mining and scoping is driven by the facts that global statistics seldom provide useful insight and that most relationships in spatial datasets are geographically regional, rather than global. Furthermore, when using traditional association rule mining, regional patterns frequently fail to be discovered due to insufficient global confidence and/or support. In this paper, we systematically study this problem and address the unique challenges of regional association mining and scoping: (1) region discovery: how to identify interesting regions from which novel and useful regional association rules can be extracted; (2) regional association rule scoping: how to determine the scope of regional association rules. We investigate the duality between regional association rules and regions where the associations are valid: interesting regions are identified to seek novel regional patterns, and a regional pattern has a scope of a set of regions in which the pattern is valid. In particular, we present a reward-based region discovery framework that employs a divisive grid-based supervised clustering for region discovery. We evaluate our approach in a real-world case study to identify spatial risk patterns from arsenic in the Texas water supply. Our experimental results confirm and validate research results in the study of arsenic contamination, and our work leads to the discovery of novel findings to be further explored by domain scientists.

Methane Occurrences in Aquifers Overlying the Barnett Shale Play with a Focus on Parker County, Texas

Clusters of elevated methane concentrations in aquifers overlying the Barnett Shale play have been the focus of recent national attention as they relate to impacts of hydraulic fracturing. The objective of this study was to assess the spatial extent of high dissolved methane previously observed on the western edge of the play (Parker County) and to evaluate its most likely source. A total of 509 well water samples from 12 counties (14,500 km2 ) were analyzed for methane, major ions, and carbon isotopes. Most samples were collected from the regional Trinity Aquifer and show only low levels of dissolved methane (85% of 457 unique locations <0.1 mg/L). Methane, when present is primarily thermogenic (δ13 C 10th and 90th percentiles of -57.54 and -39.00‰ and C1/C2+C3 ratio 10th, 50th, and 90th percentiles of 5, 15, and 42). High methane concentrations (>20 mg/L) are limited to a few spatial clusters. The Parker County cluster area includes historical vertical oil and gas wells producing from relatively shallow formations and recent horizontal wells producing from the Barnett Shale (depth of ∼1500 m). Lack of correlation with distance to Barnett Shale horizontal wells, with distance to conventional wells, and with well density suggests a natural origin of the dissolved methane. Known commercial very shallow gas accumulations (<200 m in places) and historical instances of water wells reaching gas pockets point to the underlying Strawn Group of Paleozoic age as the main natural source of the dissolved gas.