• Energy Research

Accurate characterization of heat transfer in a wellbore during drilling, which includes fluid circulation, is important for wellbore stability analysis. In this work, a pseudo-3D model is developed to simultaneously calculate the heat exchange between the flowing fluid and the surrounding media (drill pipe and rock formation) and the in-plane thermoelastic stresses. The cold drilling fluid descends through the drill pipe at constant injection rates and returns to the ground surface via the annulus. The fluid circulation will decrease the wellbore bottom temperature and reduce the near-wellbore high compressive stress, potentially leading to tensile fracturing of the well. The governing equations for the coupled heat transfer stress problem are formulated to ensure that the most important parameters are taken into account. The wellbore is subject to a non-hydrostatic in situ far-field stress field. In modeling heat exchange between fluid and surrounding media, the heat transfer coefficients are dependent on fluid properties and flow behavior. Analytical solutions in the Laplace space are obtained for the temperatures of the fluid in both the drill pipe and annulus and for the temperature and stress changes in the formation. The numerical results in the time domain are obtained by using an efficient inversion approach. In particular, the near-well stresses are compared for the cases with fixed and time-dependent cooling wellbore conditions. This comparison indicates that the using a fixed temperature wellbore conditions may over-estimate or under-estimate the bottom-hole stress change, potentially leading to wellbore stability problems.

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.

Abstract Multiple hydraulic fractures have been proposed for improving the performance of an enhanced geothermal system (EGS) by providing conductive flow pathways and increased contact area between flowing fluid and surrounding rock formation. Use of more fractures incurs a higher drilling and hydraulic fracturing cost, but the additional cost can be offset by improved operation performance of an EGS. In this paper, a model is presented for efficiently predicting the output temperature so as to optimize the number of fractures and fracture spacing to maximize the EGS lifetime under a constant circulation rate. This optimal spacing is shown to arise due to the interplay among number of fractures, fracture spacing, well depth, and the pre-existing geothermal gradient. Specifically, under a typical geothermal gradient associated with EGS for a 5 km total vertical depth of the well, the number of fractures N and the equal fracture spacing d have optimal values: 6 ⩽ N ⩽ 13 and 30 m ⩽ d ⩽ 90 m. In addition, the semi-analytical solution method presented is effective and efficient in computation and, for this reason, is useful for optimizing the design of a geothermal reservoir with multiple layers at equal or non-equal spacing.

AbstractThe 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.

The Caney shale is an emerging hydrocarbon play located in southwest Oklahoma, USA. Within the Caney shale exist facies which were initially dubbed “reservoir” and “ductile” based on evaluation of well logging data. While past work has shown the distinction of “brittle” and “ductile” is not mechanically justifiable according to formal definitions, the current work shows some important differences between nominally ductile and reservoir zones. First, the “ductile” zones are more clay rich and have textural differences which can be expected to lead to differences in mechanical properties. One important impact of these differences is observed in triaxial creep experiments showing the “ductile” zones are more prone to creep deformation. Numerical simulations predict the “reservoir” zones will experience very little proppant embedment due to creep deformation of hydraulic fractures around proppant particles. On the other hand, “ductile” zones can be expected to undergo creep-driven proppant embedment leading to loss of fracture aperture ranging up to 100% loss, depending upon the spatial density of the proppant distribution. Hence, this research shows the identification of nominally “ductile” zones from well logs, while a misnomer, can be useful in finding clay-rich, creep-prone zones which will be the most prone to proppant embedment and hence vulnerable to greater production decline over time.

AbstractWe review the techniques of below‐ground wireless communication in the oil and gas industry. A historical and theoretical analysis of pressure wave and electromagnetic communication is presented. Case studies for both technologies and their current applications are evaluated to identify the limitations of each method and opportunities for innovation. Finally, the possibilities of smart well technology are discussed with focus on sensors powered wirelessly for the continuous monitoring of shale oil/gas reservoirs using electromagnetic methods. We conclude that the critical challenges are associated with powering the devices, which must perform for periods of months to years and must be able to generate sufficiently powerful signals to overcome the large signal attenuation associated with electromagnetic wave propagation through geological media.

Deep geothermal from the hot crystalline basement has remained an unsolved frontier for the geothermal industry for the past 30 years. This poses the challenge for developing a new unconventional geomechanics approach to stimulate such reservoirs. While a number of new unconventional brittle techniques are still available to improve stimulation on short time scales, the astonishing richness of failure modes of longer time scales in hot rocks has so far been overlooked. These failure modes represent a series of microscopic processes: brittle microfracturing prevails at low temperatures and fairly high deviatoric stresses, while upon increasing temperature and decreasing applied stress or longer time scales, the failure modes switch to transgranular and intergranular creep fractures. Accordingly, fluids play an active role and create their own pathways through facilitating shear localization by a process of time-dependent dissolution and precipitation creep, rather than being a passive constituent by simply following brittle fractures that are generated inside a shear zone caused by other localization mechanisms. We lay out a new theoretical approach for the design of new strategies to utilize, enhance and maintain the natural permeability in the deeper and hotter domain of geothermal reservoirs. The advantage of the approach is that, rather than engineering an entirely new EGS reservoir, we acknowledge a suite of creep-assisted geological processes that are driven by the current tectonic stress field. Such processes are particularly supported by higher temperatures potentially allowing in the future to target commercially viable combinations of temperatures and flow rates.