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A heat extraction process between hot dry rock formation and a cylindrical well with a tubing installed inside is simulation. A wellbore/reservoir coupling formulation is proposed and solutions for temperature, fluid pressure along the annulus and tubing, and the induced pore pressure, temperature and stresses induced inside the HDR formation adjacent to the well bore are calculated. The heat extraction from the geothermal formation by injecting cold water into a tubing and circulating out from the annulus can be evaluated. Surface temperature and cold water injecting rate can be controlled to achieve desired efficiency.
Enormous geothermal energy resources exist worldwide (Raymond 2018). It can supply a renewable and clean source of power with the heat removed from a geothermal reservoir being naturally replenished. The high capacity factor of geothermal power makes geothermal energy particularly attractive as a renewable base load energy supply. With the decreasing cost of geothermal installations in deep hot dry rock (HDR), enhanced geothermal systems (EGS) have the potential to replace more costly and environmentally unfriendly technologies (Grasby 2011). EGS in HDR and Enhanced Oil Recovery (EOR) or hydraulic fracturing (HF) of shale gas and shale oil formations using super-critical CO2 are technologies gaining more attention recently for environmental and energy efficiency considerations. In low-permeability HDR or shale formations, HF may further stimulate energy transfer processes by creating a large surface area. Fluid (Δp) and heat flow (ΔT) through intact rock are diffusion processes, and enhanced flux accompanies a larger exchange surface area. Seeing the critical role of hydraulic fracturing (McLennan 1980) in EGS to achieve higher production efficiency, extensive studies are conducted (McTique, 1989; Karshige, 1989, Wang and Papamichos, 1994; 1999, Wang 2017). It has been pointed out that drastic thermal stress changes when massive cold water is injected at a lower temperature into a deep HDR formation contributes to the initiation and propagation of fractures in HDR, which can not be justified by traditional hydraulic fracturing theory and is therefore referred to as thermal fracturing (Clifford et al.1991, Charlez et al. 1996). Calculation of thermal stress changes that induces thermal fractures and their geometry changes including the thermal cracking processes requires a fully coupled thermal-hydraulic-mechanical (THM) model. This model consists of two mass balance equations for the fracture and a matrix systems diffusion process with small portion of free gas flow. A dynamic thermal cracking zone can be created and considered once the effective tensile stresses exceed the tensile strength near a wellbore or hydraulic fractures. In addition, two mass balance equations, in the fracture and matrix systems respectively, and one equilibrium equations are coupled to the two aforementioned energy equations. Parts of these equations are nonlinear and stress dependent. Therefore solving this set of equations is challenging, yet the solution is a key to practical completion design and consequently researchers and companies have allocated effort intensively to find answer to this challenge in different ways. Over the years, there have been quite a few attempts made to simulate thermal fractures (Abousleiman et al. 1996, Tarasovs and Ghassemi 2010, Hofmann et al. 2016). Nevertheless, there are challenges yet to overcome at least from the following perspectives. First, to accurately assess the thermal stress, the thermal convection associated temperature distribution in reservoir must be properly addressed (Wang and Dusseault 2003); secondly, to evaluate the potential zone in the reservoir where thermal fracture could be initiated and propagating, from a boundary condition's perspective, the overburden stress redistribution within the reservoir must also be carefully addressed (Osorio et al. 1999); Thirdly, boundary element method has been proposed and a kernel function corresponding to a temperature change inside the hydraulic fracture is required. Developing such a function and determining the heat transfer process along a hydraulic fracture with thermal leakage term are critical. Fourthly, calculating the radius and evaluating the THM properties of a thermal cracking zone surrounding a wellbore and hydraulic fracture are extremely important for thermal energy extraction and heat exchange efficiency in the EGS. lastly but not the least, to predict the thermal fracture propagation in a fractured deep geothermal reservoir, the disturbance by local natural fractures must be properly addressed (Wang 2017).
Onwumelu, Chioma (University of North Dakota) | Kolawole, Oladoyin (Texas Tech University) | Bouchakour, Imene (University of North Dakota) | Tomomewo, Olusegun (University of North Dakota) | Adeyilola, Adedoyin (Central Michigan University)
The Magnetic Resonance Imaging (MRI) log and the Nuclear magnetic resonance (NMR) are resourceful in addressing various scientific questions in petroleum geology, and they have been universally utilized in estimating total porosity due to its repeatability. Notwithstanding, the field applicability of NMR in lieu of MRI logs to estimate total porosity, have not been fully explored. The objective of our study is to develop a novel correlation between the NMR core analyses performed in the laboratory and the field MRI logs. In this study, firstly, we examined various core samples using 2MHz Geospec NMR core analyzer, and our results are compared to results from magnetic resonance imaging (MRI) log taken at 1MHz. Secondly, we performed a detailed analysis of the MRI logs, and NMR core analysis of Bakken Formation. We then evaluated the petrophysical properties of the investigated cores including its porosity, water saturation, and permeability. Our results show that there is a reasonable degree of concordance between the compared investigated results. The results from our study provided a more efficient correlation between MRI log and NMR core by considering the differences in sample volume and difference in frequency.
The Bakken Formation is one of the most prolific unconventional shale plays in North America (EIA, 2019). This formation was deposited from the Late Devonian to Early Mississippian in the Williston Basin and overlies portions of North Dakota, Montana in the United States, and portions of Manitoba and Saskatchewan in Canadian Provinces (Fig. 1). Bakken consists of four members; the upper and lower member which are black organic-rich shales, the middle member, and Pronghorn members are mixed siliciclastic and carbonates. The Lower Bakken Shale overlies the Pronghorn Member or, where the Pronghorn is absent, it rests uncomfortably upon the Three Forks Formation and overlain by the Lodgepole Formation (Webster, 1984; Meissner, 1978). The upper and lower Bakken are the source rocks while the middle member serves as a reservoir for oil produced from the upper and lower Bakken (Lefever et al., 1991; Nordeng, 2009; Nesheim, 2019) and has low porosity and permeability, particularly for a reservoir rock. Bakken shales exhibit high gammaray response as a result of adsorption of uranium over an extended period from seawater under reducing conditions, hence are easily recognizable and used for correlation purposes. Well-logging tools are used extensively in the petroleum industry to identify physical properties of rocks downhole, for example, resistivity, density which are then converted to provide petrophysical properties of interest (permeability, porosity, oil and gas zone). Nuclear Magnetic Resonance (NMR) is a method used extensively in petroleum geology to total porosity and to measure the pore size distribution (McKenon et al., 1999.)
Magsipoc, E. (University of Toronto) | Li, M. (University of Toronto) | Abdelaziz, A. (University of Toronto) | Ha, J. (University of Toronto) | Peterson, K. (University of Toronto) | Grasselli, G. (University of Toronto)
The serial section technique was used to construct a high-resolution and high-quality fracture network image stack of a true triaxial hydraulic fracturing experiment on a shale sample from the Montney formation. The stack was used to create a point cloud and fracture surface meshes that were used for fracture analysis. Fractures were separated by subtracting the fracture intersections from the point cloud then applying a connected components algorithm to separate them. Point clouds were generated from these fractures and were thinned to achieve a 1-voxel thickness. After thinning, they were smoothed to reduce the aliasing effect from the image stack grid structure. Fractures were identified as either a bedding or non-bedding fracture by proxy of their orientation. Then, their surfaces were analyzed using a directional roughness metric. This roughness metric was used along with information about the stress state to evaluate the peak shear strength criterion for each individual fracture. The slipping potential of these fractures under the stress state applied by the true triaxial frame was estimated by the ratio of the actual shear stress on the fracture and the peak shear strength criterion.
Hydraulic fracturing (HF) creates flow channels either by opening pre-existing planes of weakness or by creating new ones within the rock matrix. The geometries of these fractures differ depending on a variety of influencers such as bedding, rock fabric, material strength, the local stress environment, and spatial heterogeneities embedded within the rock mass. The morphologies of these fractures can provide useful information on the expected fracture geometry and production of a reservoir. This can be achieved by fracture geometry quantification with roughness metrics and aperture to gain information for estimating fluid resistance and proppant performance. However, this information is not easy to obtain from the field.
Laboratory HF experiments provide useful insights to the mechanics of hydraulic fracturing performed in the field. Because they are physically accessible, the fractures created by the experiment can be opened and examined. Tan et al. (2017) illustrates an example of an examination of the fracture networks of multiple HF experiments performed under true triaxial stress. Their experiments provided insights on the sensitivity of the fracture network geometry to fluid viscosity and injection rate. However, this required them to take apart the sample to gain access to internal fractures. While they were only interested in the general fracture structure, this action may have potentially lost information on the smaller fractures within the network.
Shang, S. G. (CNOOC China Limited) | Gao, K. C. (CNOOC China Limited) | Wu, X. (COSL-EXRPO Testing Services Co.) | Lin, H. (CNOOC China Limited) | Tan, Q. (China University of Petroleum) | Weng, H. Y. (China University of Petroleum) | Liu, W. (China University of Petroleum)
In the well test or production process, wellbore stability plays a decisive role in designing the reasonable test pressure difference and maintaining long-term stable production. Therefore, avoiding wellbore instability is a prerequisite for reducing development risks and improving economic efficiency. In this paper, the wellbore instability in the production process is regarded as a quasi-static mechanical problem under negative pressure conditions. A series of the laboratory experiments were carried out to simulate the process of wellbore destruction, in which the thick-walled cylinder used is artificially made by sandy conglomerate. Combined with the acoustic emission instrument, the stress condition of the wellbore failure was determined. In order to extend the experimental results to the real underground environment, the scale effect must be considered. Therefore, based on previous research conclusions and the results of laboratory experiments on sand production, the rock mechanical parameters were recalibrated. As an application example, according to the regional in-situ stress condition of the Bohai Oilfield in China, the test pressure difference of two wells in Bohai Oilfield were predicted. Finally, the method mentioned above was proved to be practical by field application.
Wellbore stability has long been considered one of the most difficult problems in the drilling and completion process. During well test, if the test pressure difference is set unreasonably, it will cause not only the inaccuracy of the productivity evaluation, but also the wellbore instability or collapse.
Many scholars have used thick-walled cylinder theory or experiment to analyze the wellbore stability and achieved meaningful results, as discussed by Warlick, L.M. et al., 2009 and Li, Q.D. et al., 2011. Therefore, the stress state of rock failure is obtained through the experiment of thick-walled cylinder combined with acoustic emission equipment in this paper. In addition, considering the influence of failure criteria and scale effect on wellbore stability, the rock mechanical parameters were recalibrated to make the prediction results more realistic. It should be noted that the recalibrated mechanical parameters are not the same as the mechanical parameters measured by uniaxial or triaxial compression experiments, which will be explained in detail later.
Thombare, A. (MetaRock Laboratories) | Gokaraju, D. V. (MetaRock Laboratories) | Mitra, A. (MetaRock Laboratories) | Govindarajan, S. (MetaRock Laboratories) | Guedez, A. (MetaRock Laboratories) | Aldin, M. (MetaRock Laboratories)
Sand production in poorly consolidated and unconsolidated clastic reservoirs has costs associated with corrosion of field equipment and damage to surface facilities. Estimating the onset of sanding and the amount of sand produced is crucial to any successful sand management strategy. Orientation of in-situ stress also plays a key role. This paper explores the relationship between the orientation of the failure observed in an advanced thick wall cylinder (ATWC) test and the measured velocity profile in an azimuthal velocity anisotropy (AVA) measurement. Integration of a high accuracy load cell into the ATWC test enables the detection of onset of failure and measurement of the volume and rate of sand production. Results of ATWC tests showed that the orientation of failure occurs in either of the significant axes of the AVA profile (either the minimum or the maximum velocity orientation). The results of the ATWC test can be used as input to commonly used sanding models. Incorporating the AVA measurement into the ATWC workflow and comparison of results may provide additional insight into the stress memory of the rock.
Many ongoing research efforts in the O&G industry are focused on providing an insight into field development, increasing overall recovery factors, and providing full justification into the field economics. Critical decisions to maximize production are constantly carried out by reservoir engineers to design optimal depletion policies while minimizing possible subsurface formation damage. Increased costs associated with sand production during hydrocarbon extraction remains to be a challenge for hydrocarbon producers in unconsolidated, poorly consolidated, and weak intergranular cementation rocks. The increased costs are directly associated with waste management, damage to surface facilities, field equipment corrosion, reduction in productivity, and in some cases, plugging of the wellbore.
Sand production process is initiated either by rock failure caused by mechanical instability (Tronvall and Fjaer, 1994) or erosion due to hydrodynamic instability (Vardoulakis, 1986). Multiple sand prediction models and workflows have been proposed over the years (Morita et al., 1989; Nouri et al., 2004; Ewy et. al., 1999; Willson et al., 2002; Van den Hoek et. al., 2003; Santana and Likrama, 2016). Simple analytical models that predict sand production and the catastrophic failure rely primarily on establishing a rock failure criterion based on the rock strength. The rock strength parameters used in the above-mentioned models are the Uniaxial Compressive Strength (UCS) of the rock and the collapse pressure obtained from Thick-walled cylinder tests (TWC). While the UCS provides the strength of the rock, Wu and Tan (2000) show that the TWC test represents the wellbore perforation in the subsurface to a significantly higher degree as the plasticity effects are incorporated in the test.
This study presents new workflows to estimate in-situ horizontal stresses using routinely acquired caliper logs while drilling. A physics-based, analytical solution is used to relate borehole deformations to the in-situ stresses, rock mechanical properties, and drilling mud pressure. A machine learning model is used as a mapping function to predict the minimum and maximum horizontal stresses given other known and unknown parameters in the analytical solution. Through incorporating probability analysis using Monte Carlo simulation, estimates of the two horizontal stresses are provided. When a field measurement of the minimum horizontal stress is available, a modified workflow can be used to estimate the maximum horizontal stress only. The workflows have been demonstrated in this paper through an application to a field case study in the Appalachian Basin.
Estimating the magnitude and orientation of in-situ stresses is of practical importance in many petroleum applications such as hydraulic fracturing, wellbore stability, and reactivation of pre-existing fractures or faults. In terms of magnitude, the minimum horizontal stress is often adequately measured using micro-fracs, mini-fracs, leakoff tests, or extended leakoff tests. The maximum horizontal stress, on the other hand, is typically measured indirectly and generally more challenging to estimate. Constraining the magnitude of the maximum horizontal stress requires detailed observations of tensile borehole failures (drilling-induced fractures) and/or compressive borehole failures (breakouts) (Zoback 2010).
Since specialized well logs are needed, such detailed observations of the borehole may not always be available. What is almost always available in vertical or slightly deviated wells is four-arm caliper log measurements, which provide useful information about the shape of the borehole after drilling.
If we assume that borehole deformations remain within the elastic limit (minimal yielding/failure), one can relate the deformed borehole shape, geomechanical properties and in-situ stresses through Equations 1 and 2 for a vertical borehole (Han and Yin 2018):
An optimum hydraulic fracturing treatment design is critical to achieve a successful well stimulation operation due to technical and economical limitations of hydraulic fracturing operations in unconventional reservoirs. Well stimulations methods through the conjunction of hydraulic fracturing and horizontal drilling have enhanced hydrocarbon production in unconventional reservoirs making shale oil and gas production technically and economically possible. The primary function of a fracturing treatment is to increase reservoir contact area by inducing long fracture half-length and higher fractured propped area with greater fluid volume injection and better transportation of proppants. The success of a fracture treatment depends greatly on selecting a suitable fracturing fluid that has capability to create long fracture half-length and carry the proppants deep enough into the fractures. In oil and gas industry, high viscosity friction reducers (HVFRs) have recently been successfully applied across all leading shale plays in North America including Bakken, Permian, and Eagle Ford. This study is aimed at examining the influence of application of HVFRs on effective fracture half-length compared to a traditional linear gel. The results of the study were examined to determine how HVFRs can be an effective fracture fluid system in shale reservoirs. The results show that using produced water with HVFRs can lead to improved proppant transport and higher fracture-half-length compared to conventional linear gel fluids. Compared to the traditional hydraulic fracturing fluids, the study shows the many potential advantages that HVFRs offers including greater proppant transport ability, larger fractured propped area, chemical cost reduction and the ability to reduce operation equipment on site. Reusing produced water can be an intelligent decision to lessen environmental footprint and decrease operational expenses. The conclusions from this research can be applied to other unconventional shale plays, such as Eagle Ford and Permian Basin for optimization ideas.
Energy is essential for human development and as global oil and gas demand has been increasing with strict environmental regulations while extracting the hydrocarbons, a lot of challenges for the oil and gas exploration and production companies have been increased as well. Exploring more hydrocarbons to keep a balance between supply and demand, discovering new unconventional prospects to substitute the depleting oil and gas reserves are some of key challenges faced by the oil and gas sector.
This paper presents a conceptual model of Pressuremeter Testing (PMT) in oil and gas wells. The elastic rock deformation was simulated to characterize the mechanical state of the rock using the cavity expansion theory. The results generated from the numerical approach demonstrated the impact of the stress relief during the excavation process on the borehole displacements. Moreover, the impact of the geometrical shape of the borehole on the PMT loading was discussed and analyzed. Several numerical models are conducted to simulate the PMT loading using Eidsvolt Siltstone and Warwick Sandstone properties under anisotropic and isotropic in-situ stress contrasts. Characterizing the mechanics of the geomaterials can be obtained from the core samples. However, the in-situ mechanical state of the rock mass in oil and gas wells is hypothetically described. The results showed apparent difference in the mechanical state of the rock based on the rock type and the surface contact between the PMT and borehole.
In-situ rock testing in oil and gas wells requires an in-depth analysis of borehole mechanical responses in order to obtain representative measurements of the rock formation. During the drilling process, it is crucially important to minimize wellbore instability to be able to sequentially recover the full mechanical responses during the Pressuremeter testing (PMT). Optimum drilling practices should be implemented to minimize wellbore instability problems such as collapse, breakouts and washouts. The borehole's wall failure is an indication of major stress relief, which may influence the in-situ measurements conducted by the PMT.
The PMT is a standard in-situ testing procedure to investigate the mechanical state of subterranean formations. It is based on cavity expansion theory. The test is typically used to study the soil and rock mechanics (i.e., strength, deformational characteristics and in-situ stresses) for underground applications such as drilling, tunneling, excavation, and mining (Clarke, 1994). The mechanical behavior of the soil and rock may follow the same physics. However, compared to soil applications, the stress relief due to oil and gas well drilling varies significantly based on the regional in-situ stress contrasts, rock type and rock fabric. Moreover, the borehole shapes in the oil and gas wells are usually irregular, which may affect the PMT results. The initial mechanical responses of the wellbore govern the state of stresses exerted by the contraction and expansion mechanism at the borehole circumference. Drilling fluid forms filter cake around the wellbore creating a barrier between the formation rock and borehole. The pressure gradient of drilling fluid is vital to mechanically minimize borehole instability in problematic formations.
The workflow for modeling sonic logging response of boreholes in anisotropic formations subject to the formation stress is presented. It enables computing the dispersion curves of any borehole mode, including the flexural and quadrupole ones. The key steps are determining static reference stress-induced state of the formation, finding effective elastic moduli tensor in the framework of the third order elasticity theory, and computing the dispersion curves of borehole modes using semi-analytical technique. The workflow is exemplified by computing the effect of the formation stress on the dispersion curves of the flexural modes of boreholes for Berea sandstone. Developed methodology can be used to gain new insights into formation stress estimation from sonic logging measurement. In addition, it presents opportunities for developing advanced computationally efficient processing algorithms.
The anisotropy measurement from the dispersion analysis of sonic logging data has proven to be a vital source of information for the subsurface stress field (Donald et al., 2013). It allows estimating both the direction and the magnitude of the stresses. To analyze the possibilities and limitations of this measurement, an efficient numerical procedure is required. Such modeling involves solving both the static mechanical problem to determine the prestressed state of the formation and finding the characteristics of elastic wave propagation in the borehole, for example, flexural waves. Direct 3D simulation, although possible, is quite computationally demanding. The situation is further complicated by the fact that the subsurface stress results into inhomogeneous distribution of the effective elastic moduli tensor and lowers its symmetry. For example, its crystal system can become orthorhombic or even a less symmetric one. The alternative procedure employs the semi-analytical finite element method (SAFE) to compute the spectrum of the borehole modes (Ellefsen et al., 1991; Zharnikov and Syresin 2015; Fang et al., 2015). Using SAFE method is the key step, which results in significant speed up and improved accuracy. Among its advantages is the ability to handle reliably and in uniform manner arbitrary inhomogeneities in the plane orthogonal to the borehole axis and arbitrary anisotropy. All steps of the procedure can be implemented using standard algorithms (either open-source or commercial ones). Separate steps of this workflow were already reported. For example, the methodology to compute the reference static stressed state was demonstrated by (Gaede et al., 2012); the technique to compute the dispersion curves of boreholes modes in anisotropic medium was proposed by (Ellefsen et al., 1991); Fang et al. modeled acoustic response of the borehole under stress adopting Mavko's approach to the computation of the deformed reference state (Fang et al., 2015). One of the important differences of our work from that of Fang et al. is in using laboratory measured thirdorder elastic constants. Present work describes the approach and the workflow and exemplifies its capabilities by modeling and analyzing the results of anisotropy measurements for several cases.
Increase in subsurface temperature causes changes in physical & mechanical properties of rocks thereby causing instability in the strata which results in rock failure & surface subsidence. In this study, sandstone rock samples were collected from the Damodar River Valley of Dhanbad, India and have been subjected to laboratory experiments to evaluate the temperature effects on sandstone rock. Individual rock samples were given a heat treatment at a specified temperature. The temperature range of 200degC to 1200 degC is considered with the upper limit following the highest reported temperatures in the region. Under this heat treatment, the sandstone samples were first heated at a specified temperature for continuous 6 hours a day and 7 days. After this process, their physical properties (mineralogy, grain size and spontaneous imbibition by water and mechanical properties (Uniaxial compressive strength-UCS, tensile strength, ultrasonic wave velocities etc.) were determined in the laboratory.
The result obtained shows that the temperature has a significant effect on the measured rock properties an attempt has been made to explain these changes using thin-section analysis. For example, the trend observed on UCS versus temperature crossplot suggest an increase in strength up to 400DegC and then decrease upto 1200 DegC. The initial increasing trend is attributed to the removal of moisture and change in compactness whereas the decreasing UCS trend is the result of the development of multiple fractures. These fractures enhance the secondary porosity and are evident in the thin sections heated to 600 degC,800 degC,1000 degC and 1200 degC. Because of the changes at the granular level, most of the physical and mechanical properties of the sandstone rock are influenced.
Many of the mining areas in the eastern part of India near the Damodar River are facing underground coal fires. Approximately 70 fires have been reported in the Jharia coalfield. Their subsurface fires have led to ground collapses in some of the areas, swallowing man-made structures and people in the abyss