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.     

Predicting Water Resource Impacts of Unconventional Gas Using Simple Analytical Equations

The rapid expansion in unconventional gas development over the past two decades has led to concerns over the potential impacts on groundwater resources. Although numerical models are invaluable for assessing likelihood of impacts at particular sites, simpler analytical models are also useful because they help develop hydrological understanding. Analytical approaches are also valuable for preliminary assessments and to determine where more complex models are warranted. In this article, we present simple analytical solutions that can be used to predict: (1) the spatial extent of drawdown from horizontal wells drilled into the gas‐bearing formation, and rate of recovery after gas production ceases; (2) the potential for upward transport of contaminants from the gas‐bearing formation to shallow aquifers during hydraulic fracturing operations when pressures in the gas‐bearing formation are greatly increased; and (3) the potential downward leakage of water from shallow aquifers during depressurization of gas‐bearing formations. In particular, we show that the recovery of pressure after production ceases from gas‐bearing shale formations may take several hundred years, and we present critical hydraulic conductivity values for intervening aquitards, below which the impact on shallow aquifers will be negligible. The simplifying assumptions inherent in these solutions will limit their predictive accuracy for site‐specific assessments, compared to numerical models that incorporate knowledge of spatial variations in formation properties and which may include processes not considered in the simpler solutions.     

Analytical solution for two-phase flow in a wellbore using the drift-flux model

This paper presents analytical solutions for steady-state, compressible two-phase flow through a wellbore under isothermal conditions using the drift flux conceptual model. Although only applicable to highly idealized systems, the analytical solutions are useful for verifying numerical simulation capabilities that can handle much more complicated systems, and can be used in their own right for gaining insight about two-phase flow processes in wells. The analytical solutions are obtained by solving the mixture momentum equation of steady-state, two-phase flow with an assumption that the two phases are immiscible. These analytical solutions describe the steady-state behavior of two-phase flow in the wellbore, including profiles of phase saturation, phase velocities, and pressure gradients, as affected by the total mass flow rate, phase mass fraction, and drift velocity (i.e., the slip between two phases). Close matching between the analytical solutions and numerical solutions for a hypothetical CO₂ leakage problem as well as to field data from a CO₂ production well indicates that the analytical solution is capable of capturing the major features of steady-state two-phase flow through an open wellbore, and that the related assumptions and simplifications are justified for many actual systems. In addition, we demonstrate the utility of the analytical solution to evaluate how the bottomhole pressure in a well in which CO₂ is leaking upward responds to the mass flow rate of CO₂-water mixture.     

Uniform head in horizontal and vertical wells

The steady-state head within a fully penetrating well may be estimated by evaluating the Thiem equation at the radius of the well. A method is presented here to extend results from the Thiem equation to horizontal wells and to partially penetrating wells. The particular model used in this investigation is based upon the analytic element method; it accurately reproduces a boundary condition of uniform head along the cylindrical surface at the perforated face of the well. This model is exercised over a representative range of parameters including the well's length, radius, and pumping rate, and the aquifer's hydraulic conductivity and thickness. Results are presented in a set of figures and tables that compare the well's drawdown to the drawdown that would have been obtained using the Thiem solution with the same pumping rate and radius. A methodology is presented to estimate the head within a horizontal or partially penetrating well by adding a correction term to results that can be readily obtained from computer models of vertical fully penetrating wells. This approach may also be used to contrast the differences in head between horizontal and vertical wells of various lengths, radii, and placement elevations.     

A method for evaluating horizontal well pumping tests

Predicting the future performance of horizontal wells under varying pumping conditions requires estimates of basic aquifer parameters, notably transmissivity and storativity. For vertical wells, there are well-established methods for estimating these parameters, typically based on either the recovery from induced head changes in a well or from the head response in observation wells to pumping in a test well. Comparable aquifer parameter estimation methods for horizontal wells have not been presented in the ground water literature. Formation parameter estimation methods based on measurements of pressure in horizontal wells have been presented in the petroleum industry literature, but these methods have limited applicability for ground water evaluation and are based on pressure measurements in only the horizontal well borehole, rather than in observation wells. This paper presents a simple and versatile method by which pumping test procedures developed for vertical wells can be applied to horizontal well pumping tests. The method presented here uses the principle of superposition to represent the horizontal well as a series of partially penetrating vertical wells. This concept is used to estimate a distance from an observation well at which a vertical well that has the same total pumping rate as the horizontal well will produce the same drawdown as the horizontal well. This equivalent distance may then be associated with an observation well for use in pumping test algorithms and type curves developed for vertical wells. The method is shown to produce good results for confined aquifers and unconfined aquifers in the absence of delayed yield response. For unconfined aquifers, the presence of delayed yield response increases the method error.     

Modeling Flow into Horizontal Wells in a Dupuit-Forchheimer Model

Horizontal wells or radial collector wells are used in shallow aquifers to enhance water withdrawal rates. Groundwater flow patterns near these wells are three-dimensional (3D), but difficult to represent in a 3D numerical model because of the high degree of grid refinement needed. However, for the purpose of designing water withdrawal systems, it is sufficient to obtain the correct production rate of these wells for a given drawdown. We developed a Cauchy boundary condition along a horizontal well in a Dupuit-Forchheimer model. Such a steady-state 2D model is not only useful for predicting groundwater withdrawal rates but also for capture zone delineation in the context of source water protection. A comparison of our Dupuit-Forchheimer model for a radial collector well with a 3D model yields a nearly exact production rate. Particular attention is given to horizontal wells that extend underneath a river. A comparison of our approach with a 3D solution for this case yields satisfactory results, at least for moderate-to-large river bottom resistances.     

Analytical and semi-analytical solutions of horizontal well capture times under no-flow and constant-head boundaries

The closed-form analytical solutions and semi-analytical solutions of capture times to horizontal wells are derived for different recovery scenarios. The capture time is the time a fluid particle takes to flow to the well. The first scenario is recovery from a confined aquifer in which the influence of regional groundwater flow upon the capture time is included. The second scenario is recovery from underneath a water reservoir in which the top boundary of the aquifer is constant-head. The third scenario is recovery from a low-permeability layer bounded above and below by much higher permeability media. Closed-form solutions are provided for the cases with: (1) a center or a bottom well for the first scenario; (2) a bottom well for the second scenario; and (3) a center well for the third scenario. Semi-analytical solutions are provided for general well locations for those scenarios. Solutions for both isotropic and anisotropic media are studied. These solutions can be used as quick references to calculate the capture times, and as benchmarks to validate numerical solutions. The limitations of the analytical solutions are analyzed. Our results show that the top and bottom no-flow boundaries of an aquifer constrain the vertical flow, but enhance the horizontal flow, resulting in elongated iso-capture time curves. When constant-head boundaries are presented, water can infiltrate vertically across those boundaries to replenish the aquifers, resulting in less elongated iso-capture time curves.     

Drawdown Distribution in the Vicinity of Nonvertical Wells

Recent developments in subsurface intake systems for ocean desalination plants are considering use of angled wells (slant wells) completed in permeable materials beneath the ocean floor. Conventional drawdown equations for vertical or horizontal wells are inadequate to properly describe the drawdown distribution in the vicinity of slant wells. Using the principle of superposition combined with standard well hydraulics, universal drawdown equations (UDE) are presented which calculate the drawdown distribution in the vicinity of production wells with inclination angles ranging from 0° (horizontal wells) to 90° (vertical wells). The method is computationally simple and other than the normal assumptions for standard well equations, it only requires that the calculated drawdown represent the drawdown which would be measured in a fully penetrating observation well. Solutions using the UDE are developed for confined, unconfined and semi‐confined (leaky) aquifers and compared with analytical equations for vertical and horizontal wells, and with a numerical model for slant wells. The UDE is also applied to pumping test data from the Dana Point slant well project in Southern California.     

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.     

Saltwater Upconing Due to Cyclic Pumping by Horizontal Wells in Freshwater Lenses

This article deals with the quantification of saltwater upconing below horizontal wells in freshwater lenses using analytical solutions as a computationally fast alternative to numerical simulations. Comparisons between analytical calculations and numerical simulations are presented regarding three aspects: (1) cyclic pumping; (2) dispersion; and (3) finite horizontal wells in a finite domain (a freshwater lens). Various hydrogeological conditions and pumping regimes within a dry half year are considered. The results show that the influence of elastic and phreatic storage (which are not taken into account in the analytical solutions) on the upconing of the interface is minimal. Furthermore, the analytical calculations based on the interface approach compare well with numerical simulations as long as the dimensionless interface upconing is below 1/3, which is in line with previous studies on steady pumping. Superimposing an analytical solution for mixing by dispersion below the well over an analytical solution based on the interface approach is appropriate in case the vertical flow velocity around the interface is nearly constant but should not be used for estimating the salinity of the pumped groundwater. The analytical calculations of interface upconing below a finite horizontal well compare well with the numerical simulations in case the distance between the horizontal well and the initial interface does not vary significantly along the well and in case the natural fluctuation of the freshwater lens is small. In order to maintain a low level of salinity in the well during a dry half year, the dimensionless analytically calculated interface upconing should stay below 0.25.     

Towards Quantifying the Likelihood of Water Resource Impacts from Unconventional Gas Development

Gas production from unconventional reservoirs has led to widespread environmental concerns. Despite several excellent reviews of various potential impacts to water resources from unconventional gas production, no study has systematically and quantitatively assessed the potential for these impacts to occur. We use empirical evidence and numerical and analytical models to quantify the likelihood of surface water and groundwater contamination, and shallow aquifer depletion from unconventional gas developments. These likelihoods are not intended to be exact. They provide a starting point for comparing the probabilities of adverse impacts between types of water resources and pathways. This analysis provides much needed insight into what are “probable” rather than simply “possible” impacts. The results suggest that the most likely water resource impacts are surface water and groundwater contamination from spills at the well pad, which can be as high as 1 in 10 and 1 in 100 for each gas well, respectively. For wells that are hydraulically fractured, the likelihood of contamination due to inter-aquifer leakage is 1 in 10⁶ or lower (dependent on the separation distance between the production formation and the aquifer). For gas-bearing formations that were initially over-pressurized, the potential for contamination from inter-aquifer leakage after production ceases could be as high as 1 in 400 where the separation between gas formation and shallow aquifer is 500 m, but will be much lower for greater separation distances (more characteristic of shale gas).     

北京地区大灰厂井与五里营井氦气观测资料的对比分析

对比分析了北京市地震局丰台大灰厂井和延庆五里营井的氦气观测资料,发现由于井水深度、井水类型和水温的不同,丰台大灰厂井氦气含量明显低于延庆五里营井的氦气含量;两口井氦气年变都是冬高夏低;日变形态基本一致,都表现为一峰一谷的形态;两口井氦气含量与观测环境温度负相关。     

超短半径径向水平井抽采煤层气渗流规律的数值模拟

为得到超短半径径向水平井开采煤层气过程中的气体渗流规律以及进行产量预测,在基本假设条件下,建立了径向水平井开采煤层气的固流耦合渗流数学模型;在一定的边界条件及初始条件下,利用Matlab软件进行编程计算后,得到直井和不同数目分支径向水平井开采煤层气1000天后的压力场、速度场和气产量变化规律。数值模拟结果表明,在一定的生产区域和开采时间,随着径向水平井分支数目的增加,煤储层压力下降范围更广,气体流速场干扰加强,压力漏斗降大面积扩展,煤层气有效供气区及解吸面积大幅增长,煤层气解吸能力及稳产能力加强,煤层气产量大幅度增加;同时,气产量增幅随着井筒分支数目的增加而下降,分支井数目理论上应存在一个最优值。模拟结果显示了超短半径径向水平井技术开采煤层气的有效卸压作用,对煤层气工业增产技术的选择和钻孔方案的布置具有重要的理论指导意义。     

Free-Phase Gas Detection in Groundwater Wells via Water Pressure and Continuous Field Parameters

Detection of free-phase gas (FPG) in groundwater wells is critical for accurate assessment of dissolved gas concentrations and the occurrence of FPG in the subsurface, with consequent implications for understanding groundwater contamination and greenhouse gas emissions. However, identifying FPG is challenging during routine groundwater monitoring and there is poor agreement on the best approach to detect the occurrence of FPG in groundwater. In this study, laboratory experiments in a water column were designed to mimic nonflowing and flowing conditions in a groundwater well to evaluate how the presence of FPG affects water pressure and commonly used continuous field parameters. The laboratory results were extrapolated to interpret field data at an abandoned exploration well with episodic release of free-gas CO₂. The FPG effect on water pressure varied between flowing and nonflowing wells, and depending on whether the FPG was above or below the sensor. Electrical conductivity values were decreased and/or behaved erratically when FPG was present in the water column. Findings from this study have shown that the combined measurement of water pressure, electrical conductivity, and total dissolved gas pressure can provide information about the occurrence of FPG in groundwater wells. Measurement of these parameters at different depths can also provide information about relative depths and amounts of FPG within the well water column. This approach can be used for long-term monitoring of groundwater gases, managing gas-locking in production wells with gassy groundwater, and measuring fugitive greenhouse gas emissions from groundwater wells.     

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.     

Gas segregation in dykes and sills

Many basaltic volcanoes emit a substantial amount of gas over long periods of time while erupting relatively little degassed lava, implying that gas segregation must have occurred in the magmatic system. The geometry and degree of connectivity of the plumbing system of a volcano control the movement of magma in that system and could therefore provide an important control on gas segregation in basaltic magmas. We investigate gas segregation by means of analogue experiments and analytical modelling in a simple geometry consisting of a vertical conduit connected to a horizontal intrusion. In the experiments, degassing is simulated by electrolysis, producing micrometric bubbles in viscous mixtures of water and golden syrup. The presence of exsolved bubbles induces a buoyancy-driven exchange flow between the conduit and the intrusion that leads to gas segregation. Bubbles segregate from the fluid by rising and accumulating as foam at the top of the intrusion, coupled with the accumulation of denser degassed fluid at the base of the intrusion. Steady-state influx of bubbly fluid from the conduit into the intrusion is balanced by outward flux of lighter foam and denser degassed fluid. The length and time scales of this gas segregation are controlled by the rise of bubbles in the horizontal intrusion. Comparison of the gas segregation time scale with that of the cooling and solidification of the intrusion suggests that gas segregation is more efficient in sills (intrusions in a horizontal plane with typical width:length aspect ratio 1:100) than in horizontally-propagating dykes (intrusions in a vertical plane with typical aspect ratio 1:1000), and that this process could be efficient in intermediate as well as basaltic magmas. Our investigation shows that non-vertical elements of the plumbing systems act as strong gas segregators. Gas segregation has also implications for the generation of gas-rich and gas-poor magmas at persistently active basaltic volcanoes. For low magma supply rates, very efficient gas segregation is expected, which induces episodic degassing activity that erupts relatively gas-poor magmas. For higher magma supply rates, gas segregation is expected to be less effective, which leads to stronger explosions that erupt gas-rich as well as gas-poor magmas. These general physical principles can be applied to Stromboli volcano and are shown to be consistent with independent field data. Gas segregation at Stromboli is thought likely to occur in a shallow reservoir of sill-like geometry at 3.5 km depth with exsolved gas bubbles 0.1–1 mm in diameter. Transition between eruptions of gas-poor, high crystallinity magmas and violent explosions that erupt gas-rich, low crystallinity magmas are calculated to occur at a critical magma supply rate of 0.1–1 m³ s^− 1.     

Comparative Evaluation for Characterization of Produced Water Generated from Oil,Gas, and Oil–Gas Production Fields

A reliable wastewater characterization is a prerequisite for the selection of an acceptable treatment strategy for produced water which exhibits significant differences due to the varied kinds of wells, seasonal changes, and formation types. A complete characterization of produced water generated from oil, gas, and oil–gas fields in Turkey was performed based on seasonal and locational variations. The results showed that the produced water generated from oil field wells was highly polluted and wastewater volume was higher in comparison to gas and oil–gas field wells. Besides, the characterization of produced water was varying in a wide range based on seasonal and locational variations. Useful relationships were observed between chloride, sodium, bromide, and total dissolved solids concentrations. The results can be used in the design, operation, and optimization of wastewater treatment systems of petroleum and oil industries for future studies.     

Transient analysis of the source of water to wells: Cape Cod, Massachusetts

A transient flow modeling analysis for potential public-supply wells on western Cape Cod, Massachusetts, demonstrates the difference between transient and steady-state recharge areas can have important implications for wellhead protection. An example of a single pumping well illustrates that commonly used steady-state time-related capture areas do not represent the recharge area and travel times of water being pumped from the well until sufficient time has elapsed for steady-state flow conditions to be established. Until that time, transient recharge areas are needed to account for the portion of water discharging from the well that entered the aquifer before pumping started. An example of two pumping wells demonstrates the same area at the water table cannot supply water to more than one well under steady-state flow conditions. Transient recharge areas to multiple wells can overlap, however, until steady-state flow conditions are established. The same area can, therefore, be a source of water to more than one well during early pumping times, and the water pumped from a given well may derive from source areas, including contaminated areas, that do not lie within the well's steady-state recharge area.     

Design, Installation, and Uses of Combination Ground Water and Gas Sampling Wells

Waste disposal sites with volatile organic compounds (VOCs) frequently contain contaminants that are present in both the ground water and vadose zone. Vertical sampling is useful where transport of VOCs in the vadose zone may effect ground water and where steep vertical gradients in chemical concentrations are anticipated. Designs for combination ground water and gas sampling wells place the tubing inside the casing with the sample port penetrating the casing for sampling. This physically interferes with pump or sampler placement. This paper describes a well design that combines a ground water well with gas sampling ports by attaching the gas sampling tubing and ports to the exterior of the casing. Placement of the tubing on the exterior of the casing allows exact definition of gas port depth, reduces physical interference between the various monitoring equipment, and allows simultaneous remediation and monitoring in a single well. The usefulness and versatility of this design was demonstrated at the Idaho National Engineering and Environmental Laboratory (INEEL) with the installation of seven wells with 53 gas ports, in a geologic formation consisting of deep basalt with sedimentary interbeds at depths from 7.2 to 178 m below land surface. The INEEL combination well design is easy to construct, install, and operate.     

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 (δ¹³C 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.