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Tracking the migration of injected CO2 is critical to understanding the performance of subsurface intervals selected for CO2 sequestration. Subsurface CO2 injection may cause a deformation at the surface of the earth. Measuring and analysing the shape and magnitude of this surface deformation provides confidence that sequestered CO2 will remain in the target formations and can alert operators to the existence of hidden faults or fractures which may necessitate redesign of the injection schedule or remediation of the geological hazards. Surface deformation information for onshore injection operations can be obtained via Interferometric Synthetic Aperture Radar (InSAR) satellite imagery or an array of high-precision tiltmeters installed in 10–15 m deep boreholes. However, in the case of offshore injection operations, InSAR data is not available. Due to the lack of tilt data at In Salah field at Krechba, Algeria, synthetic tilt data has been produced using a 3D forward model. The synthetic tilt time-series data at ten locations around each injection well has been used in inverse analysis. Results show that the shape and direction of the CO2 plume in the subsurface can be accurately determined through inverse analysis of the tilt time-series data.

Uncertainty is an undeniable aspect of underground operations, such as wellbore stimulation treatments, where combined rock and fluid interaction add a layer of complexity to the uncertainty. There are social and environmental concerns about the probable outcome of operations like hydraulic fracturing. Hydraulic fracturing treatments may affect the integrity of sub-surface geological strata or might initiate unexpected potential risks to the environment when the created fracture extends beyond its engineered design. Therefore, it is necessary to investigate a range of possible scenarios by which the fracture may experience a deviation from its planned behaviour. In this study, we model the uncertainty associated with hydraulic fracturing using fracture growth simulation. The uncertainty of a range of treatment parameters, such as pumping flow rate, injection duration and mechanical properties of the underground geological layer, is investigated. Monte Carlo simulation is used to examine different probable fracturing scenarios and numerous fracturing simulations with numerical and analytical models. The probability analysis is performed in a case study to identify the cumulative distribution functions (CDFs) of fracture growth. The emerging least, median and most likely situations of fracture growth are analysed to evaluate the fracturing uncertainty. Our results indicate that the numerical modelling approach may predict a more extensive fracture growth in the vertical plane. The numerical model may suggest a more conservative way to address environmental concerns. The resulting cumulative distribution of probabilities suggests the CDFs of the analytical model as the lower band for fracture length, whereas the numerical CDFs presents the upper band.

Leak-off characteristics during hydraulic fracturing operation are difficult to determine but yet critical in developing conventional and unconventional reservoirs with natural fractures and other weak structural planes (e.g. micro-faults, weak beddings). When hydraulic fractures interact with natural fractures, they will either be arrested or transect the natural fractures depend on the leak-off characteristic of the natural fractures. The effective leak-off characteristic in a naturally fractured reservoir is an essential input for hydraulic fracturing simulation and consequent completion design as well as reservoir simulation (e.g., dual porosity and dual permeability) and consequent production optimization. A novel method of estimating the effective leak-off characteristic in a naturally fractured reservoir is developed directly from hydraulic fracturing diagnostic tests such as minifrac and DFIT utilizing eXtended Finite Element Method (XFEM)-based 3D hydraulic fracturing model. Complex behaviors of hydraulic fractures interacting with natural fractures are simulated in the XFEM-based hydraulic fracturing model and history-matched with minifrac/DFIT data (i.e., treating pressure), in order to estimate effective leak-off characteristics of naturally fractured reservoirs.

Coal seam gas (CSG) or coal bed methane production has grown exponentially in Australia over the last two decades with currently nearly 7000 productive wells and another 18,750 wells planned over the next five to ten years. To address concerns over environmental contamination by hydraulic fracture fluids (HFF) attributed to (i) incidents involving poor surface handling of HFF and other fluids with potential migration pathways in soil and shallow groundwater, and (ii) leakage pathways arising from HFF injection into coal seams and unintended migration of these chemicals, the National assessment of chemicals associated with coal seam gas extraction in Australia (the Assessment) was undertaken. The Assessment included a review of international studies on unconventional gas migration pathways to provide prior knowledge and comparison for use in the Australian study. The international literature highlighted that accidents with HFF were mainly due to surface operations and included leaking equipment and spills. Contamination risks of groundwater from hydraulic fracturing itself were found to be very small based on analysis of micro-seismic and groundwater hydrochemistry data; geologic modelling of vertical fracture growth further reveals a low risk of leakage pathways developing in aquifers confined by deep shale formations. This is due to limitations on the fracture growth vertically across aquitards often hundreds of meters thick, retention within the shale of limited amounts of injected fluid, and preferential fracture growth at shallow depths in the horizontal direction. These arguments are broadly applicable to Australian CSG basins. However, important differences exist, such as the reduced thickness in Australia of the aquitards that separate the targeted gas resource from groundwater. Also, hydraulic fracturing in Australian coal seams is practised only when permeabilities are too low for gas extraction to be economical without stimulation. From the nearly 10,000 CSG wells drilled in the Bowen and Surat Basins in Queensland, only 6% have received hydraulic fracturing to date. The reduced risk of leakage pathways developing during CSG production in Australian basins is further corroborated by geologic criteria based on modelling and observations. Criteria include encountering certain favourable conditions during drilling/injection, i.e. (i) interfaces, such as natural fractures, faults, and bedding planes, which promote offsetting and branching, or rock layers with higher fracture toughness causing the cessation or reduction in fracture growth, (ii) narrow fractures due to a relatively higher elastic modulus, leading to higher viscous flow loss, (iii) high permeability layers, and (iv) overlying layer(s) with a higher confining stress. In addition to the leakage pathways considered in North American shale gas basins involving (i) pre-existing fractures and faults, or (ii) flow up the production well due to poor casing or cementing, plausible chemical migration pathways in Australian CSG basins are due to (iii) connectivity via a fracture in or extended out of the coal seam formation between CSG wells and water bores co-located in the same formation, and (iv) poor integrity water bores enhancing inter-aquifer connectivity. These plausible pathways are described and used in subsequent work as the basis of risk assessments for contamination at the local- and regional scale.

The physics of gas uptake in coal constrains the feasibility of coal seam gas extraction and carbon sequestration in coal measures. While X-ray tomography using xenon as an X-ray opaque tracer gas has been used in the past to study gas uptake in coal specimens, synchrotron sources enable high-resolution micro-tomography datasets of high quality to be acquired in minutes adding the ability to quantify the dynamics of gas sorption over time in five coals of similar rank on the microscopic scale. In the present work we describe a synchrotron micro-computed-tomography (micro-CT) study of gas uptake in coal using Xe, Kr and CO2 gases. Measurement of gas uptake over time for Xe and Kr in different specimens and of CO2 induced swelling are reported, together with an analysis of gas diffusion profiles and their correspondence to those expected from diffusion models.The rate of penetration was CO2 > Kr > Xe in all cases, though the rates of penetration varied enormously between different coals. In some cases even 2 months was not enough to allow the Xe to equilibrate fully. The gas distribution was also shown to respond rapidly to flushing with CO2.

Optimization of well placement in a geothermal system is an important topic for maximizing the heat economically extracted from a conductive geothermal reservoir. In order to investigate the role of well placement, this paper presents a semi-analytical model in which fluid circulates in a single, horizontally planar geothermal reservoir with a constant hydraulic aperture via dipole wells in the presence of a 2D areal or regional flow field. By using a new coordinate system based on the velocity potential and the streamline function, analytical solutions in the Laplace space for the temperature field are found, which are then numerically inverted to obtain time-domain results. The effects of some factors such as well separation, areal flow direction, flow rate, and the velocity of the areal flow on heat recovery are investigated. It is found that the dimensionless areal flow velocity, U0 = v0ωπL/Q, and the angle of the areal flow, β, play an important role when changing other parameter to maximize the output temperature and the lifetime of the dipole well system. When U0 ≤ 0.5, the angle for minimizing interflow between wells should be β = 0; when 0.5 0.7854, the injection well should be placed downstream from the production well.

Summary In this paper, the problem of a hydraulic fracture (HF) interacting with a pre-existing natural fracture (NF) has been investigated with a cohesive zone finite-element model. The model fully couples fluid flow, fracture propagation, and elastic deformation, taking into account the friction between the contacting fracture surfaces and the interaction between the HF and the NF. The effect of the field conditions—such as in-situ stresses, rock and fracture mechanical and geometrical (initial conductivity of the NF) properties, intersection angle, and the treatment parameters (fracturing fluid viscosity and injection rate)—on the HF propagation behavior has been analyzed. The finite-element-modeling results provide detailed quantitative information on the development of various types of HF/NF interaction, interfacial stress distribution, fracture-geometry evolution, and injection-pressure history, and allow us to gain an in-depth understanding of the relative roles of various parameters. The value of a parameter calculated as the product of fracturing-fluid viscosity and injection rate can be used as an indicator to gauge if crossing or diverting behavior is more likely. In addition, using a finite-element approach allows the analysis to be extended to include the effects of fluid leakoff and poroelastic effect, and allows the study of HF height growth through a system of nonhomogeneous layers and their bedding planes.

We show that simple breakage of a crystalline rock (gabbro) in tension begets further breakage of rock in the area around the first crack that is self-sustaining and spontaneous and that is detected via sustained acoustic emissions (AE). The result is a sequence of AE events that is statistically similar to aftershocks from earthquakes, that scales with the size of the main crack, and that we were able to observe for days following the initial breakage in laboratory-scale experiments. A new model for aftershock generation that is based on residual strain relaxation is shown to be consistent with the observed hyperbolic decay of the event rate with time and with the manner in which the decay law scales with the size of the main rupture.

The development of reliable experimental techniques for characterization of chemoporomechancial shale–fluid interactions is important for the design of drilling fluids that maximize shale stability. In this context, testing of millimeter-scale specimens is promising because small specimens require shorter test durations and are more readily available from offcuts of preserved core or potentially from drill cuttings or wellbore cave-in material than larger core plugs that are required for more conventional experimentation. Here we present experiments wherein we measure the axial displacement of 4 mm long by 4 mm diameter cylindrical shale specimens that are subjected firstly to a mechanical axial loading and then to an osmotic loading associated with a sudden increase in the salinity of the surrounding fluid. The response to both stages of loading is consistent with theoretical, chemoporoelastic predictions. In particular, the model predicts two types of behavior depending on the ratio between the reflection coefficient and the so-called chemomechanical coupling coefficient that quantifies the volumetric strain as a result of a change in ion content. Consistent with predictions, both monotonic shrinkage and initial shrinkage followed by partial recovery are observed in our testing campaign which includes 20 shales from a variety of geological settings. Quantitative characterization is also carried out by selecting chemoporoelastic parameter values that minimize the mismatch between the data and the model. The results show that the reflection coefficient and the chemomechanical coupling parameter are correlated with each other and with both the Cation Exchange Capacity (CEC) and the Specific Surface Area (SSA). Based on the consistency of the data from test to test and with the model, together with the fact that the key chemoporoelastic coefficients are sensibly correlated with CEC and SSA, we conclude that these millimeter-scale experiments are able to provide useful characterization for better understanding and predicting shale–fluid interactions.

This paper presents static fatigue laboratory experiments conducted in three different configurations. The experiments are designed so as to cause delayed tensile failure in dry Gabbro specimens after the sustained application of a static subcritical load. Results from the static fatigue experiments give a time to failure of the specimen related to the applied static load. In the presented experiments, results spanning up to six orders of magnitude of time to failure were collected for three-point bending, four-point bending, and indirect tensile (Brazilian) specimens. The data supports an exponential relationship between tensile stress and time to failure, noting that a power law relationship is also supported by the data. The salient difference among the configurations is hypothesized to be the size of the region of the specimen that is subjected to a close approximation of the maximum tensile stress. The time to failure at a given nominal tensile stress, the decrease in time to failure associated with a given increase in stress (i.e. the slope in a semi logarithmic plot), and the magnitude of the scatter of the data about the best-fit curve are all observed to correlate inversely with the nominal size of the region subjected to the maximum tensile stress.

The integrity of the wellbore completion under injection conditions is vital for the effective, long term storage of carbon dioxide. Here we experimentally demonstrate and mathematically model fluid-driven debonding of the wellbore annulus in order to provide a fundamental basis for well design. We show that self-limiting versus self-sustaining propagation of the annular debonding are distinguished by the sign of a fluid buoyancy parameter that involves a non-trivial relationship between the hydrostatic pressure variation of the fluid with depth and the clamping stress provided by the internally-pressurized casing/cement system. The theory also gives a series of scaling relationships that can be used to predict the rate of growth of the debonding and the fluid flux through the annulus for various growth regimes. The experiments confirm the theoretical predictions of debonding growth rate for the limiting case of zero-buoyancy. We also observe azimuthal debonding extending around 1/2 to 3/4 of the well annulus in the experiments, which is shown to be consistent with physical insights that can be derived from the theoretical model. We conclude that the clamping stress on the well annulus is a critical quantity for hydraulic isolation of the well, and therefore appropriate design of the casing/cement system relative to the intended injection conditions is necessary for the integrity of CO2 injection wells. © 2013 Elsevier Ltd.

The concept of CO2 storage relies on the long-term sealing properties of both the geological trap and the wells needed to inject and monitor CO2. Well integrity, a classical topic in the oil and gas industry, is thus critical for the performance of any CO2 storage complex in terms of containment. Thanks to the very low permeability of cement (typically less than 0.1 mDarcy); a properly cemented well ensures hydraulic isolation between reservoirs layers and shallow aquifers. Moreover, such low matrix permeability limits the cement/ CO2 interactions over the active period of a storage complex (of the order of 100 years) to a few meters. Leaks from a cased and cemented well, if any, are known to occur only through defects: mud-channel (in case of poor cement placement), cracks within cement and more importantly micro-annulus at the casing/cement or/and cement/formation interfaces. This last category of defects can lead to substantial leakage rate. Its importance has been recognized by the oil and gas industry since the 1960's leading to the study of cement "bonding" properties. In the scope of CO2 storage, the understanding, modeling and monitoring of the occurrence of micro-annulus becomes of prime importance. We analyze the complete loading history of a cemented completion from cement placement to routine well operations. Further to classical failure type assessment used in the oil and gas industry (i.e. fail/no fail, good cement/bad cement), we aim at quantifying the vertical extent, azimuthal coverage and width of the created defects to adequately transform failure types into leakage pathways. Such a prediction of connected defects/leakage pathways along a cemented well imposes to consistently integrate the effects of lithology, geomechanics, cement placement (fluid loss, hydration), completion design and knowledge of pressure and thermal variation during the life of the well. The modeling of such a problem can be made tractable by recognizing the intrinsic hierarchy of lengthscales of a cemented well (i.e. the cement annulus is much thinner than the well dimension). The original three-dimensional problem is reduced to a much simpler two-dimensional one, which in turn can even be further reduced to a one-dimensional configuration in a lot of practical cases. Typical cases of interface debonding due to well de-pressurization and thermal cooling taking place after cement placement are carefully analyzed. Furthermore, we specially focus on injectors. Despite the use of all current best practices during well construction, the injection in itself can lead to the propagation of a debonding crack between cement and casing or cement and formation due to the high pressure generated at the perforations level. Such a problem has already been reported in hydraulic fracturing operations, and is a reasonable explanation of observed well leaks for injectors. A consistent model predicting the initiation and propagation of interface debonding during injection operations is then compared to carefully designed laboratory experiments. Such experiments also confirm that the azimuthal coverage of the interface debonding is only partial (i.e. less than 360°), an observation consistent with cement evaluation logs acquired on CO2 injectors. Finally, best practices to achieve and retain well integrity of CO2 injectors are highlighted from a careful examination of the results of both the model and the experiment. © 2011 Published by Elsevier Ltd.

Decommissioning of wells and well pads (plugging and abandonment of the well and rehabilitation of the well pad) is an important activity in coal seam gas developments due to the large number of wells drilled and their co-location with other land uses. Successful decommissioning will need to be conducted in a way that is effective, efficient, complies with regulatory requirements and is socially acceptable. This study sought to understand the perspective of industry, government and local stakeholders on the decommissioning process and asked the question ‘what does successful decommissioning mean’? The study was conducted through workshops held in Camden, Chinchilla and Narrabri involving industry, government and local residents. All stakeholders agreed that the goal of successful decommissioning is to effectively have no legacy issues arising from the abandoned well or well pad, in perpetuity. However, there were differences in the confidence that stakeholders had in the process of achieving this outcome, largely based on the varying levels of understanding of well abandonment. This lack of confidence and understanding contributes to cross-cutting themes that emerged from the workshops. Local stakeholders expressed a strong desire for independent oversight and assessment of well abandonment processes, with increased transparency and access to information on abandoned wells in an understandable form. They also stated that long-term monitoring of wells post abandonment would assist in providing them with confidence that wells can be successfully decommissioned.

We discuss a method of detecting localised fracturing that potentially requires only one channel. The method is based on the notion that the fracture propagation involves generation of acoustic events from its contour. It is proposed that the number of events (microcracks) generated at each step of fracture propagation could be proportional to the fracture size to a certain power called the localisation exponent. This dependence of the number of generated events on the fracture size (the event coherence) leads to a shift to higher frequency (the “blue shift”) in the combined spectrum of the events as compared to the spectrum of randomly generated events. This concept was applied to the results of a laboratory test in which hydraulic fracture was driven by injecting glycerine into a 200x200x120mm block of polycrystalline gabbro. We show that there is indeed a blue shift in the spectrum of the arrival times at any one sensor that seems to correspond with the growth of a localized hydraulic fracture. The localisation exponent is able to distinguish between the cases of the fracture contour length roughly proportional to, and more slowly than proportional to, the nominal fracture radius.

Surface area, surface charge and the exchangeability of cations have long been known as factors in determining the physical and mechanical properties of shales. Such properties are related to the fine grain size of the various clay minerals and also the particle shapes, edge-face microstructural arrangements and are impacted by the likes of salinity and depositional environment. In general, the siltier a given clay or shale, the lower their cation exchange capacity (CEC) and specific surface area (SSA). CEC and SSA have direct impacts on mechanical and flow properties. Wellbore instability can be caused by the development of osmotic pressures resulting from differences between pore fluid composition and drilling fluid composition and the resultant time dependent effects based on permeability. Such instability can be mitigated by the use of oil-based muds or for example high KCl water-based muds. Electrical and dielectric properties are also dependent on mineral surface charge and related directly to the CEC of a given shale, especially properties such as resistivity (or conductivity) and permittivity (dielectric constant). This paper will detail SSA and CEC values of shales from multiple basins worldwide and also from individual boreholes to demonstrate their role for shale rock properties.