Spatial Risk Analysis of Hydraulic Fracturing near Abandoned and Converted Oil and Gas Wells

Interaction between hydraulically generated fractures and existing wells (frac hits) could represent a potential risk to groundwater. In particular, frac hits on abandoned oil and gas wells could lead to upward leakage into overlying aquifers, provided migration pathways are present along the abandoned well. However, potential risk to groundwater is relatively unknown because few studies have investigated the probability of frac hits on abandoned wells. In this study, actual numbers of frac hits were not determined. Rather, the probability for abandoned wells to intersect hypothetical stimulated reservoir sizes of horizontal wells was investigated. Well data were compiled and analyzed for location and reservoir information, and sensitivity analyses were conducted by varying assumed sizes of stimulated reservoirs. This study used public and industry data for the Eagle Ford Shale play in south Texas, with specific attention paid to abandoned oil and gas wells converted into water wells (converted wells). In counties with Eagle Ford Shale activity, well‐data analysis identified 55,720 abandoned wells with a median age of 1983, and 2400 converted wells with a median age of 1954. The most aggressive scenario resulted in 823 abandoned wells and 184 converted wells intersecting the largest assumed stimulated reservoir size. Analysis showed abandoned wells have the potential to be intersected by multiple stimulated reservoirs, and risks for intersection would increase if currently permitted horizontal wells in the Eagle Ford Shale are actually completed. Results underscore the need to evaluate historical oil and gas activities in areas with modern unconventional oil and gas activities.     

Commingled Fluids in Abandoned Boreholes: Proximity Analysis of a Hidden Liability

The interactions between old abandoned wellbores of suspect well integrity with hydraulic fracturing (HF), enhanced oil recovery (EOR), or salt water disposal (SWD) operations can result in upward leakage of deep aqueous liquids into overlying aquifers. This potential for upward fluid migration is largely unquantified as monitoring abandoned wells is rarely done, and leakage may go unnoticed especially when in deeper aquifers. This study performs a proximity analysis between old abandoned wells and HF, EOR, and SWD wells, and identifies commingled old abandoned wellbores, which are those wells where groundwater may flow from one aquifer to one or more other aquifers, to identify the locations with the greatest potential for upward aqueous fluid migration at three study sites in the Western Canadian Sedimentary Basin. Our analysis indicates that at all three study sites there are several locations where HF, EOR, or SWD operations are located in close proximity to a given old abandoned well. Much of this overlap occurs in formations above typically produced hydrocarbon reservoirs but below exploited potable aquifers, otherwise known as the intermediate zone, which is often connected between abandonment plugs in old abandoned wells. Information on the intermediate zone is often lacking, and this study suggests that unanticipated alterations to groundwater flow systems within the intermediate zone may be occurring. Results indicate the need for more field-based research on the intermediate zone.     

Potential Contaminant Pathways from Hydraulically Fractured Shale to Aquifers

Hydraulic fracturing of deep shale beds to develop natural gas has caused concern regarding the potential for various forms of water pollution. Two potential pathways—advective transport through bulk media and preferential flow through fractures—could allow the transport of contaminants from the fractured shale to aquifers. There is substantial geologic evidence that natural vertical flow drives contaminants, mostly brine, to near the surface from deep evaporite sources. Interpretative modeling shows that advective transport could require up to tens of thousands of years to move contaminants to the surface, but also that fracking the shale could reduce that transport time to tens or hundreds of years. Conductive faults or fracture zones, as found throughout the Marcellus shale region, could reduce the travel time further. Injection of up to 15,000,000 L of fluid into the shale generates high pressure at the well, which decreases with distance from the well and with time after injection as the fluid advects through the shale. The advection displaces native fluids, mostly brine, and fractures the bulk media widening existing fractures. Simulated pressure returns to pre‐injection levels in about 300 d. The overall system requires from 3 to 6 years to reach a new equilibrium reflecting the significant changes caused by fracking the shale, which could allow advective transport to aquifers in less than 10 years. The rapid expansion of hydraulic fracturing requires that monitoring systems be employed to track the movement of contaminants and that gas wells have a reasonable offset from faults.     

An Analytical Model for Hydraulic Fracturing in Shallow Bedrock Formations

A theoretical method is proposed to estimate post‐fracturing fracture size and transmissivity, and as a test of the methodology, data collected from two wells were used for verification. This method can be employed before hydrofracturing in order to obtain estimates of the potential hydraulic benefits of hydraulic fracturing. Five different pumping test analysis methods were used to evaluate the well hydraulic data. The most effective methods were the Papadopulos‐Cooper model (1967), which includes wellbore storage effects, and the Gringarten‐Ramey model (1974), known as the single horizontal fracture model. The hydraulic parameters resulting from fitting these models to the field data revealed that as a result of hydraulic fracturing, the transmissivity increased more than 46 times in one well and increased 285 times in the other well. The model developed by dos Santos (2008) , which considers horizontal radial fracture propagation from the hydraulically fractured well, was used to estimate potential fracture geometry after hydrofracturing. For the two studied wells, their fractures could have propagated to distances of almost 175 m or more and developed maximum apertures of about 2.20 mm and hydraulic apertures close to 0.30 mm. Fracturing at this site appears to have expanded and propagated existing fractures and not created new fractures. Hydraulic apertures calculated from pumping test analyses closely matched the results obtained from the hydraulic fracturing model. As a result of this model, post‐fracturing geometry and resulting post‐fracturing well yield can be estimated before the actual hydrofracturing.     

Pressure Buildup and Brine Migration During CO2 Storage in Multilayered Aquifers

Carbon dioxide injection into deep saline formations may induce large‐scale pressure increases and migration of native fluid. Local high‐conductivity features, such as improperly abandoned wells or conductive faults, could act as conduits for focused leakage of brine into shallow groundwater resources. Pressurized brine can also be pushed into overlying/underlying formations because of diffuse leakage through low‐permeability aquitards, which occur over large areas and may allow for effective pressure bleed‐off in the storage reservoirs. This study presents the application of a recently developed analytical solution for pressure buildup and leakage rates in a multilayered aquifer‐aquitard system with focused and diffuse brine leakage. The accuracy of this single‐phase analytical solution for estimating far‐field flow processes is verified by comparison with a numerical simulation study that considers the details of two‐phase flow. We then present several example applications for a hypothetical CO₂ injection scenario (without consideration of two‐phase flow) to demonstrate that the new solution is an efficient tool for analyzing regional pressure buildup in a multilayered system, as well as for gaining insights into the leakage processes of flow through aquitards, leaky wells, and/or leaky faults. This solution may be particularly useful when a large number of calculations needs to be performed, that is, for uncertainty quantification, for parameter estimation, or for the optimization of pressure‐management schemes.     

Groundwater Protection and Unconventional Gas Extraction: The Critical Need for Field‐Based Hydrogeological Research

Unconventional natural gas extraction from tight sandstones, shales, and some coal‐beds is typically accomplished by horizontal drilling and hydraulic fracturing that is necessary for economic development of these new hydrocarbon resources. Concerns have been raised regarding the potential for contamination of shallow groundwater by stray gases, formation waters, and fracturing chemicals associated with unconventional gas exploration. A lack of sound scientific hydrogeological field observations and a scarcity of published peer‐reviewed articles on the effects of both conventional and unconventional oil and gas activities on shallow groundwater make it difficult to address these issues. Here, we discuss several case studies related to both conventional and unconventional oil and gas activities illustrating how under some circumstances stray or fugitive gas from deep gas‐rich formations has migrated from the subsurface into shallow aquifers and how it has affected groundwater quality. Examples include impacts of uncemented well annuli in areas of historic drilling operations, effects related to poor cement bonding in both new and old hydrocarbon wells, and ineffective cementing practices. We also summarize studies describing how structural features influence the role of natural and induced fractures as contaminant fluid migration pathways. On the basis of these studies, we identify two areas where field‐focused research is urgently needed to fill current science gaps related to unconventional gas extraction: (1) baseline geochemical mapping (with time series sampling from a sufficient network of groundwater monitoring wells) and (2) field testing of potential mechanisms and pathways by which hydrocarbon gases, reservoir fluids, and fracturing chemicals might potentially invade and contaminate useable groundwater.     

Flow and Containment of Injected Wastes

Proper design, construction, testing and maintenance of Class 1 (hazardous waste) injection wells can guarantee that all waste is delivered to the injection zone. To assess the effects of waste injection, analytical models were developed which predict waste movement and pressure increases within the injection zone, and describe upward permeation through confining layers.
A basic plume model was used to track waste from several injection wells with varied injection history at DuPont's Victoria Texas site. To determine the maxi-mum distance that any portion of the waste might travel, special purpose models were employed to account for (1) density differences between the waste and the native formation brine, and (2) layered permeability variation within the injection zone. The results were generalized to a "multiplying factor concept," which facilitates development of a worst-case scenario.
A pressure distribution model based on the Theis (1935) equation for radial flow was applied to the Victoria site, with modifications to account for multiple wells, injection history and geological complexities.
Permeation into an intact confining layer was investigated by a new technique based on the Hantush and Jacob (1955) "leaky aquifer" theory. The model defines the maximum permeation distance, taking into account post-injection pressure decay.
Defects within confining layers, such as faults, fractures and abandoned wells, have been considered. Studies to evaluate their detailed characteristics are continuing. Initial results indicate that faults and fractures are not likely to provide conductive pathways in Gulf Coast settings, and site-specific evaluations are required to assess the impact of abandoned wells.     

Constraints on Upward Migration of Hydraulic Fracturing Fluid and Brine

Recent increases in the use of hydraulic fracturing (HF) to aid extraction of oil and gas from black shales have raised concerns regarding potential environmental effects associated with predictions of upward migration of HF fluid and brine. Some recent studies have suggested that such upward migration can be large and that timescales for migration can be as short as a few years. In this article, we discuss the physical constraints on upward fluid migration from black shales (e.g., the Marcellus, Bakken, and Eagle Ford) to shallow aquifers, taking into account the potential changes to the subsurface brought about by HF. Our review of the literature indicates that HF affects a very limited portion of the entire thickness of the overlying bedrock and therefore, is unable to create direct hydraulic communication between black shales and shallow aquifers via induced fractures. As a result, upward migration of HF fluid and brine is controlled by preexisting hydraulic gradients and bedrock permeability. We show that in cases where there is an upward gradient, permeability is low, upward flow rates are low, and mean travel times are long (often >10⁶ years). Consequently, the recently proposed rapid upward migration of brine and HF fluid, predicted to occur as a result of increased HF activity, does not appear to be physically plausible. Unrealistically high estimates of upward flow are the result of invalid assumptions about HF and the hydrogeology of sedimentary basins.     

Determining the microseismic event source parameters from the surface seismic array data with strong correlated noise and complex focal mechanisms of the source

The world experience shows that hydraulic fracturing (fracking) is an efficient tool for increasing oil and gas production of low-permeable reservoirs in hydrocarbon fields. The fracking-induced fractures in the rock, which are hydrodynamically connected with the wells, significantly enhance the volumes of extracted hydrocarbons. Controlling the processes of fracture formation and propagation is a vital question in the oil and gas reservoir management. A key means to implement this control is provided by microseismic monitoring of fracking, which makes it possible to promptly reconstruct the geometry of the fractures from the data on seismic waves from the microearthquakes induced by the formation and propagation of fractures.     

流体-地质力学耦合建模表征水力压裂诱发地震:以加拿大Fox Creek地区为例

随着水力压裂技术在页岩气开发中的广泛应用,加拿大西部盆地的诱发地震活动显著增加.目前对于诱发地震的综合表征方法还不成熟.本文采用一种综合地质、岩石力学及流体力学的研究方法,对Fox Creek地区2015年2月8日发生的M 3.0诱发地震事件进行了综合表征.首先,利用高分辨率三维反射地震资料,采用蚂蚁体追踪技术识别潜在断层.其次,利用测井曲线和压裂施工数据等资料定量求取岩石力学及地应力参数,建立三维地质力学模型,明确水力压裂缝的空间扩展规律.最后,建立流体-地质力学耦合模型,计算水力压裂过程中断层附近的孔隙压力及局部应力变化,利用摩尔-库仑破裂准则判定断层激活的时间与空间位置,揭示本次诱发地震事件的触发机制并提出风险控制对策.结果表明,三条由Precambrian基底向上延伸至Duvernay地层的近垂直断层在水平井压裂过程中被激活.由于水平井的部分压裂缝与断层沟通,注入流体沿断层的高渗透破裂带向下迅速扩散,在基底位置激活断层并诱发M 3.0地震事件.其中孔隙压力增加是本例中断层活化的主要因素.现场措施表明,增大压裂水平井与已知断层之间的距离被可以有效地降低地震风险.因此在进行水平井钻井及压裂作业之前,明确地下断层的分布位置至关重要.     

Analysis of Wellbore Skin Samples—Typology,Composition, and Hydraulic Properties

The presence of a wellbore skin layer, formed during the drilling process, is a major impediment for the energy‐efficient use of water wells. Many models exist that predict its potential impacts on well hydraulics, but so far its relevant hydraulic parameters were only estimates or, at best, model results. Here, we present data on the typology, thickness, composition, and hydraulic properties obtained from the sampling of excavated dewatering wells in lignite surface mines and from inclined core drilling into the annulus of an abandoned water well. Despite the limited number of samples, several types of skin were identified. Both surface cake filtration and particle straining in the aquifer occur. The presence of microcracks may be a determining feature for the hydraulic conductivity of skin layers. In the case of the well‐developed water supply well, no skin layer was detected. The observed types and properties of wellbore skin samples can be used to test the many mathematical skin models.     

Performance Assessments of a Novel Well Design for Reducing Exposure to Bedrock‐Derived Arsenic

Arsenic in groundwater is a serious problem in New England, particularly for domestic well owners drawing water from bedrock aquifers. The overlying glacial aquifer generally has waters with low arsenic concentrations but is less used because of frequent loss of well water during dry periods and the vulnerability to surface‐sourced bacterial contamination. An alternative, novel design for shallow wells in glacial aquifers is intended to draw water primarily from unconsolidated glacial deposits, while being resistant to drought conditions and surface contamination. Its use could greatly reduce exposure to arsenic through drinking water for domestic use. Hypothetical numerical models were used to investigate the potential hydraulic performance of the new well design in reducing arsenic exposure. The aquifer system was divided into two parts, an upper section representing the glacial sediments and a lower section representing the bedrock. The location of the well, recharge conditions, and hydraulic properties were systematically varied in a series of simulations and the potential for arsenic contamination was quantified by analyzing groundwater flow paths to the well. The greatest risk of arsenic contamination occurred when the hydraulic conductivity of the bedrock aquifer was high, or where there was upward flow from the bedrock aquifer because of the position of the well in the flow system.     

Numerical Modeling of the Near‐Field Hydraulics of Water Wells

Numerical flow models can be a useful tool for dimensioning water wells and to investigate the hydraulics in their near‐field. Fully laminar flow can be assumed for all models calculated up to the screen. Therefore models can be used to predict—at least qualitatively, neglecting turbulent losses inside the well—the spatial distribution of inflow into the well and the overall hydraulic performance of different combinations of aquifer parameters and technical installations. Models for both horizontal (plan view) and vertical flow (cross section) to wells were calculated for a variety of setups. For the latter, this included variations of hydraulic conductivity of the screen, pump position, and aquifer heterogeneity. Models of suction flow control devices showed that they indeed can homogenize inflow, albeit at the cost of elevated entrance losses.     

Assessing Methane in Shallow Groundwater in Unconventional Oil and Gas Play Areas,Eastern Kentucky

The expanding use of horizontal drilling and hydraulic fracturing technology to produce oil and gas from tight rock formations has increased public concern about potential impacts on the environment, especially on shallow drinking water aquifers. In eastern Kentucky, horizontal drilling and hydraulic fracturing have been used to develop the Berea Sandstone and the Rogersville Shale. To assess baseline groundwater chemistry and evaluate methane detected in groundwater overlying the Berea and Rogersville plays, we sampled 51 water wells and analyzed the samples for concentrations of major cations and anions, metals, dissolved methane, and other light hydrocarbon gases. In addition, the stable carbon and hydrogen isotopic composition of methane (δ¹³C‐CH₄ and δ²H‐CH₄) was analyzed for samples with methane concentration exceeding 1 mg/L. Our study indicates that methane is a relatively common constituent in shallow groundwater in eastern Kentucky, where methane was detected in 78% of the sampled wells (40 of 51 wells) with 51% of wells (26 of 51 wells) exhibiting methane concentrations above 1 mg/L. The δ¹³C‐CH₄ and δ²H‐CH₄ ranged from ?84.0‰ to ?58.3‰ and from ?246.5‰ to ?146.0‰, respectively. Isotopic analysis indicated that dissolved methane was primarily microbial in origin formed through CO₂ reduction pathway. Results from this study provide a first assessment of methane in the shallow aquifers in the Berea and Rogersville play areas and can be used as a reference to evaluate potential impacts of future horizontal drilling and hydraulic fracturing activities on groundwater quality in the region.     

A feasibility study of borehole radar as a permanent downhole sensor

Permanent downhole sensors provide the eyes and ears to the reservoir and enable monitoring the reservoir conditions on a real‐time basis. In particular, the use of sensors and remotely controlled valves in wells and on the surface, in combination with reservoir flow models provide enormous benefits to reservoir management and oil production. We suggest borehole radar measurements as a promising technique capable to monitor the arrival of undesired fluids in the proximity of production wells. We use 1D modelling to investigate the expected signal magnitude and depth of investigation of a borehole radar sensor operating in an oilfield environment. We restrict the radar applicability to environments where the radar investigation depth can fit the reservoir size necessary to be monitored. Potential applications are steam chamber monitoring in steam assisted gravity drainage processes and water front monitoring in thin oil rim environments. A more sophisticated analysis of the limits of a radar system is carried out through 2D finite‐difference time‐domain simulations. The metal components of the wellbore casing can cause destructive interference with the emitted signal. A high dielectric medium surrounding the production well increases the amplitude of the signal and so the radar performance. Other reservoir constraints are given by the complexity of the reservoir and the dynamic of the fluids. Time‐lapse changes in the heterogeneity of the background formation strongly affect the retrieval of the target reflections and gradual fluid saturation changes reduce the amplitudes of the reflections.     

Numerical Modeling of Methane Leakage from a Faulty Natural Gas Well into Fractured Tight Formations

Horizontal drilling and hydraulic fracturing have enabled hydrocarbon recovery from unconventional reservoirs, but led to natural gas contamination of shallow groundwaters. We describe and apply numerical models of gas‐phase migration associated with leaking natural gas wells. Three leakage scenarios are simulated: (1) high‐pressure natural gas pulse released into a fractured aquifer; (2) continuous slow leakage into a tilted fractured formation; and (3) continuous slow leakage into an unfractured aquifer with fluvial channels, to facilitate a generalized evaluation of natural gas transport from faulty natural gas wells. High‐pressure pulses of gas leakage into sparsely fractured media are needed to produce the extensive and rapid lateral spreading of free gas previously observed in field studies. Transport in fractures explains how methane can travel vastly different distances and directions laterally away from a leaking well, which leads to variable levels of methane contamination in nearby groundwater wells. Lower rates of methane leakage (≤1 Mcf/day) produce shorter length scales of gas transport than determined by the high‐pressure scenario or field studies, unless aquifers have low vertical permeabilities (≤1 millidarcy) and fractures and bedding planes have sufficient tilt (～10°) to allow a lateral buoyancy component. Similarly, in fractured rock aquifers or where permeability is controlled by channelized fluvial deposits, lateral flow is not sufficiently developed to explain fast‐developing gas contamination (0‐3 months) or large length scales (～1 km) documented in field studies. Thus, current efforts to evaluate the frequency, mechanism, and impacts of natural gas leakage from faulty natural gas wells likely underestimate contributions from small‐volume, low‐pressure leakage events.     

Bioremediation in Fractured Rock: 1. Modeling to Inform Design,Monitoring, and Expectations

Field characterization of a trichloroethene (TCE) source area in fractured mudstones produced a detailed understanding of the geology, contaminant distribution in fractures and the rock matrix, and hydraulic and transport properties. Groundwater flow and chemical transport modeling that synthesized the field characterization information proved critical for designing bioremediation of the source area. The planned bioremediation involved injecting emulsified vegetable oil and bacteria to enhance the naturally occurring biodegradation of TCE. The flow and transport modeling showed that injection will spread amendments widely over a zone of lower‐permeability fractures, with long residence times expected because of small velocities after injection and sorption of emulsified vegetable oil onto solids. Amendments transported out of this zone will be diluted by groundwater flux from other areas, limiting bioremediation effectiveness downgradient. At nearby pumping wells, further dilution is expected to make bioremediation effects undetectable in the pumped water. The results emphasize that in fracture‐dominated flow regimes, the extent of injected amendments cannot be conceptualized using simple homogeneous models of groundwater flow commonly adopted to design injections in unconsolidated porous media (e.g., radial diverging or dipole flow regimes). Instead, it is important to synthesize site characterization information using a groundwater flow model that includes discrete features representing high‐ and low‐permeability fractures. This type of model accounts for the highly heterogeneous hydraulic conductivity and groundwater fluxes in fractured‐rock aquifers, and facilitates designing injection strategies that target specific volumes of the aquifer and maximize the distribution of amendments over these volumes.     

Where Does Water Go During Hydraulic Fracturing?

During hydraulic fracturing millions of gallons of water are typically injected at high pressure into deep shale formations. This water can be housed in fractures, within the shale matrix, and can potentially migrate beyond the shale formation via fractures and/or faults raising environmental concerns. We describe a generic framework for producing estimates of the volume available in fractures and undamaged shale matrix where water injected into a representative shale site could reside during hydraulic fracturing, and apply it to a representative site that incorporates available field data. The amount of water that can be stored in the fractures is estimated by calculating the volume of all the fractures associated with a discrete fracture network (DFN) based on real data and using probability theory to estimate the volume of smaller fractures that are below the lower cutoff for the fracture radius in the DFN. The amount of water stored in the matrix is estimated utilizing two distinct methods—one using a two‐phase model at the pore‐scale and the other using a single‐phase model at the continuum scale. Based on these calculations, it appears that most of the water resides in the matrix with a lesser amount in the fractures.     

Depletion Mapping and Constrained Optimization to Support Managing Groundwater Extraction

Groundwater models often serve as management tools to evaluate competing water uses including ecosystems, irrigated agriculture, industry, municipal supply, and others. Depletion potential mapping—showing the model‐calculated potential impacts that wells have on stream baseflow—can form the basis for multiple potential management approaches in an oversubscribed basin. Specific management approaches can include scenarios proposed by stakeholders, systematic changes in well pumping based on depletion potential, and formal constrained optimization, which can be used to quantify the tradeoff between water use and stream baseflow. Variables such as the maximum amount of reduction allowed in each well and various groupings of wells using, for example, K‐means clustering considering spatial proximity and depletion potential are considered. These approaches provide a potential starting point and guidance for resource managers and stakeholders to make decisions about groundwater management in a basin, spreading responsibility in different ways. We illustrate these approaches in the Little Plover River basin in central Wisconsin, United States—home to a rich agricultural tradition, with farmland and urban areas both in close proximity to a groundwater‐dependent trout stream. Groundwater withdrawals have reduced baseflow supplying the Little Plover River below a legally established minimum. The techniques in this work were developed in response to engaged stakeholders with various interests and goals for the basin. They sought to develop a collaborative management plan at a watershed scale that restores the flow rate in the river in a manner that incorporates principles of shared governance and results in effective and minimally disruptive changes in groundwater extraction practices.     

Evaluation of Methane Sources in Groundwater in Northeastern Pennsylvania

Testing of 1701 water wells in northeastern Pennsylvania shows that methane is ubiquitous in groundwater, with higher concentrations observed in valleys vs. upland areas and in association with calcium‐sodium‐bicarbonate, sodium‐bicarbonate, and sodium‐chloride rich waters—indicating that, on a regional scale, methane concentrations are best correlated to topographic and hydrogeologic features, rather than shale‐gas extraction. In addition, our assessment of isotopic and molecular analyses of hydrocarbon gases in the Dimock Township suggest that gases present in local water wells are most consistent with Middle and Upper Devonian gases sampled in the annular spaces of local gas wells, as opposed to Marcellus Production gas. Combined, these findings suggest that the methane concentrations in Susquehanna County water wells can be explained without the migration of Marcellus shale gas through fractures, an observation that has important implications for understanding the nature of risks associated with shale‐gas extraction.