ABSTRACT: Pore pressure reduction, caused by reservoir fluid production, will alter the stresses in the vicinity of a producer. These stress alterations affect the propagation of hydraulic fractures that originate e.g. during water or polymer injection into injector wells as part of enhanced oil recovery (EOR) or improvement of geothermal well productivity. In this study, we use a modified discrete element model (MDEM), coupled to the fluid-flow simulator Tough2, to investigate how hydraulic fractures are affected when growing into a zone of altered pore pressure. The study shows that flow induced stress changes can have a significant effect on hydraulic fracture propagation. Hydraulic fractures tend to bend around the producer, and the degree of deviation from the far stress field is dependent on several factors, including production rate, time, reservoir permeability, stress anisotropy and Poisson’s ratio. The stress alterations show a high sensitivity to stress anisotropy and are also affected by Poisson’s ratio.
Local stress alterations can cause deviation from the far-field stress and are important to identify for accurate reservoir management. The stress regime is commonly believed to govern fracture propagation, and local changes in the stress regime can influence hydraulic fracturing treatments and fractures created as a result of water or polymer injection. Injection treatments relevant to enhanced oil recovery (EOR) operations, as well as to operations in the geothermal industry. For example in the case where well stimulation is performed on the margins of a geothermal field with a history of prior operations.
Pore pressure changes in the reservoir during production or injection affect the effective stresses, and can cause a rotation of the principal stresses. Generally, production will increase the compressive stresses in the tangential direction and injection will increase the compressive stresses in the radial direction (Hidayati et al, 2001). If the rotation is great enough, hydraulic fractures growing in the affected region can deviate from what is anticipated by the far-field stress. It is therefore of importance to look at how hydraulic fractures are affected when growing in the vicinity of pressure-depletion induced stress changes, and under what conditions the effect is significant.
ABSTRACT: Lost circulation is a classical wellbore instability problem that is encountered during drilling. In order to minimize or avoid lost circulation, the best measure is to prevent the initiation of fracture. However, due to rocks are naturally anisotropic, the classical fracture pressure model is not applicable for anisotropic formations. Some researchers had therefore investigated the influence of transverse isotropic material parameters, but the influence of anisotropic tensile strength was ignored. The present work is to propose a novel fracture-initiation pressure model of horizontal well to investigate the influence of anisotropy on fracture-initiation pressure. The present method predicting the fracture-initiation pressure was verified by a laboratory hydraulic fracturing test. The results indicated that both anisotropic modulus and tensile strength have very distinct influence on the fracture-initiation pressure. Fracture-initiation pressure declines obviously under the influence of anisotropic modulus and anisotropic tensile strength, thus the anisotropy of modulus and tensile strength cannot be ignored. The present model can provide a more accurate method for the predicting of fracture-initiation pressure for horizontal well in anisotropic formations.
Due to the exhaustion of conventional petroleum resources, some unconventional petroleum resources, such as tight gas, shale gas, and coal-bed gas, gradually be paid more attention. To develop these unconventional petroleum resources, more and more complicated structure wells, such as directional well, horizontal well, and extended reach well, are used to enlarge the drainage area and enhance oil and gas recovery (Ma et al., 2015). However, drilling horizontal wells usually bring out some new problems, such as wellbore collapse, lost circulation, cuttings transport, the excessive drag and torque (Ma and Chen, 2015; Ma et al., 2015, 2016). Thereinto, lost circulation is a classical wellbore instability problem encountered during drilling (Zoback, 2007; Fjar et al., 2008; Chen et al., 2008; Aadnoy and Looyeh, 2011), consequently, not only lose a lot of materials and costs, but also increase the non-productive time (NPT).
ABSTRACT: Geomechanical properties are important for reservoir characterization and optimal stimulation design in the oil and gas industry. The conventional techniques, such as laboratory core analysis and downhole acoustic/wireline logging can be expensive and sometimes uncertain to process for unconventional reservoirs. In this study, a convenient and cost-effective technology is presented that uses routinely available drilling data to calculate the geomechanical properties without the need for downhole logging operations. A wellbore friction model is used to estimate the coefficient of friction and effective downhole weight on bit (DWOB) from the routinely collected drilling data. The inverted rate of penetration (ROP) models use the estimated downhole weight on bit and formation lithology constants to calculate the geomechanical properties throughout the horizontal reservoir formations such as confined compressive strength (CCS), unconfined compressive strength (UCS), Young’s modulus, permeability, porosity and Poisson’s ratio. In this article, the field case study is presented for a sample North American well applied to the lower Eagle Ford formation. The calculated geomechanical property log is also verified with tests performed on cores in reservoir rock formations.
Continuous monitoring of rock mechanical and reservoir properties along the wellbore in unconventional horizontal wells demands convenient and efficient logging techniques. The conventional logging techniques involve laboratory core analysis and well logging using sonic and resistivity image logs which are not readily available for all unconventional wells (1 in 10 or 1 in 20) mainly due to associated cost, data uncertainity and time consuming to process. Moreover there are possible risks and concerns of trapping logging tools downhole in highly deviated and horizontal wells drilled in unconventional reservoirs. For many years, researchers and engineers have been investigating several models and techniques to obtain geomechanical property logs for the successful development of unconventional resrvoirs and stimulation design for maximum hydrocarbon production. The Artificial Intelligence and Data Mining (AI&DM) or data- driven models were developed to generate synthetic geomechanical information from the conventional logs in shale plays (Eshkalak et al., 2013). The conventional log data from a shale well was used for training and calibration during neural network model development to generate the synthelic logs for other wells. This model provides better performance for the wells in proximity of the training well with actual geomechanical properties. A convenient ROP model was developed to calculate rock mechanical properties such as, confined compressive strength (CCS), unconfined compressive strength (UCS) and Young’s modulus (E) at each drilled depth from the routinely collected drilling data such as rate of penetration (ROP), weight on bit (WOB) and RPM (Hareland and Nygaard, 2007). In horizontal drilling, the actual downhole weight on bit differs from the measured surface WOB (obtained from on and off bottom hook load difference readings) due to the friction caused by drill string movement, rotation within the wellbore and wellbore geometry. A previously developed 3D wellbore friction model (torque and drag (T&D) model) was used to estimate the coefficient of friction and effective downhole weight on bit (DWOB) from the surface measurements of WOB, hook load, surface applied RPM along with the wellbore survey measurement, standpipe pressure and drill string information (Fazalizadeh et al., 2010).
ABSTRACT: The selection of an optimized wellbore trajectory is one of the key factors that determine the success of hydraulic fracturing. Geomechanics-based wellbore trajectory optimization uses a geomechanics analysis solution, such as geostress components values. For calculation convenience, the concept of Fβ -potential which is defined on the surfaces of natural fractures with inclination angle β is proposed as an index for selecting the optimized wellbore trajectory. In the simplest case, the wellbore trajectory of a tight formation should be taken in the direction of maximum horizontal stress (SH) to maximize the stimulated reservoir volume. In this case, the injection-induced fracture will propagate in the direction that is perpendicular to the axis of wellbore trajectory. When a natural fracture exists in the tight formation, injection-induced fractures are believed to be determined by those natural fractures that can open under hydraulic injection stimulation. Consequently, the task of trajectory optimization is to locate those natural fractures that are easy to open with injection. These fractures are also known as critically stressed fractures (CSF). The workflow for selecting the optimized wellbore trajectory based on geomechanics solutions and the concept of CSF is presented in this paper. For trajectory optimization focused on the primary fracturing design, the workflow is performed with the initial geostress. For the optimization focused on the fracturing design in a field that is disturbed by primary fracturing from offset wells, the workflow is performed with the stress field disturbed by primary fracturing.
Tight formation refers to shale gas/oil formations and tight sand gas/oil formations. Hydraulic fracturing is essential for production in tight formations. Trajectory optimization is a fundamental aspect of a wellbore design in a tight formation with natural fractures (Bond et al., 2006; Himmerlberg and Eckert, 2013; Manchanda et al., 2012). A deliberately optimized wellbore trajectory enables maximum efficiency of hydraulic fracturing; the value of stimulated reservoir volume (SRV) will reach its maximum if the trajectory is selected to go through the right place (sweet spot) and is in right direction.
ABSTRACT: As one of three key factors in ground motion, the effect of seismic duration on the dynamic response of gravity dam most focus on theoretical analysis, and few concrete dam model tests are carried out to discuss about it. In order to research the influence of duration on the seismic behavior of high concrete gravity dam, in this study, a 185 m gravity dam model experiment based on similarity theory is carried out on a shaking table which type is Dys-600-5-05. The inputting seismic peak ground acceleration is kept as 5.32 g, and the earthquake periods are 0.48 s, 1.44 s, 3.20 s, 6.4 s, 9.6 s, respectively. Test results show that: when the seismic duration is less than 1.44 s, the dam body has no obvious crack, and there is no change in the whole frequency. After the time of 3.2 s, crack appears at the bending position above the dam toe of downstream face, and the crack extends to the bottom of the dam and eventually develops to be a penetrating crack at the time of 9.6 s. This study suggests that the dam will not be damaged when suffered a short duration of strong earthquake even if the peak acceleration is very large. With the duration increasing of strong earthquake, the cumulative damage of gravity dam is intensified, and the frequency of dam will significantly decreased.
The seismic safety capability of dams is an issue of concern in the engineering of these structures. A dam collapse may cause direct economic losses, seismic casualties, and serious secondary disasters. In the past few decades, the researchers put a lot of energy on the dynamic response of dam during the earthquake, the main research methods include the actual observation of dam seismic response, numerical model analysis and laboratory test.
ABSTRACT: Total E&P has developed an experimental set-up allowing creation shear fracture within a cylinder sample in a conventional triaxial cell thanks to two specific heels placed on the top and bottom of the sample. Permeability tests to gas and to water, as well as measurements of normal and shear displacements can be carried out using existing facilities of a triaxial cell. In the post-failure phase of shear fracturing, dilatancy angle of a fresh fracture measured on a Vaca Muerta shale is about 24° to 38° under 30 bars of confining pressure. Mechanical opening (normal displacement) induced by fracturing is about 400 μm. Hydraulic opening to water or to gas decreases significantly when confining pressure increased from 10 bars to 120 bars. Alteration of a fresh shale fracture surface by water is characterized by the change of the hydraulic opening to gas. After presentation of the experiment set-up, the main results obtained on the mechanical behavior of the fracture and the hydraulic behavior of fracture to water and to gas flow under various stress and injection conditions are presented and discussed.
The Vaca Muerta formation of Neuquén basin, Argentina, is considered the most interesting hydrocarbon shale play in the world, and is currently the subject of intense exploration and research works and the first unconventional development projects in this country (Su K. et al 2014, Varela et al 2014). The mineralogical of the Vaca Muerta formation is reported by Askenazi et al (2013) to consist of a important, but highly variable portion of carbonate and quartz, ranging both from 10 to 80%, and consistently low clay content within the 5 to 35% range. In the area investigated by Total E&P, the average total organic carbon content (TOC) is ~4.0% in the upper part and around 6.0% in the lower part. The in situ pore pressure of the Vaca Muerta ranges from 1.7 to 2.1 sg.
Zhuang, L. (Korea Institute of Civil Engineering and Building Technology) | Kim, K. Y. (Korea Institute of Civil Engineering and Building Technology) | Jung, S. G. (University of Science and Technology) | Nam, Y. J. (University of Science and Technology) | Min, K.-B. (Seoul National University) | Park, S. (Seoul National University) | Zang, A. (Helmholtz Centre Potsdam GFZ German Research Centre for Geosciences) | Stephansson, O. (Helmholtz Centre Potsdam GFZ German Research Centre for Geosciences) | Zimmermann, G. (Helmholtz Centre Potsdam GFZ German Research Centre for Geosciences) | Yoon, J. S. (Helmholtz Centre Potsdam GFZ German Research Centre for Geosciences)
ABSTRACT: A new concept of cyclic hydraulic fracturing with cyclic injection was suggested to replace the conventional hydraulic fracturing with continuous injection to help reduce induced seismicity during fracturing. Proof of the concept was done in laboratory. Test results showed that 80% of the average breakdown pressure in continuous injection is able to induce hydraulic breakdown by cyclic injection, and the total number of cycles generally decreased with increasing maximum injection pressure. Induced seismicity reduction was confirmed based on acoustic emission monitoring results. Apertures of induced fractures in granite specimen were estimated through computed tomography (CT) images and they were relatively smaller in case of cyclic fracturing compared with conventional hydraulic fracturing. Moreover, injectivity index was calculated based on re-injection tests. The results of fracture aperture and injectivity index indicate that permeability enhancement effect for cyclic hydraulic fracturing is not as effective as conventional hydraulic fracturing considering isostatic loading condition. Hydraulic fracturing efficiency is expected to be improved by both modifying the cyclic injection style and considering hydro-shear by applying confining pressure and differential stresses to the samples.
Deep geothermal energy is renewable energy with great potential for future use. However, intact rocks in deep underground are usually low permeable and hydraulic stimulation is necessary to create a permeable reservoir for extracting geothermal energy through water circulation. The induced seismicity during stimulation is a main concern and sometimes causes a controversy in public acceptance. New stimulation methods with less induced seismicity and at the same time ensuring permeability enhancement are necessary. Cyclic hydraulic fracturing or fatigue hydraulic fracturing, as it sometimes is called, is a stimulation method to achieve a fatigue failure through cyclic loading. This concept is firstly presented by Zang et al. (2013). The key point in fatigue hydraulic fracturing is the frequent lowering of the injection pressure by cyclic injection to allow stress relaxation at the fracture tips. As a result, it is expected induced seismicity will be relieved due to release of stress. Preliminary studies on the concept of the cyclic hydraulic fracturing have been done in recent years based on experiments and numerical simulations (Yoon et al. 2015; Zimmerman et al. 2015; Zhuang et al. 2016a). Differences in injection style and fracturing results between the cyclic hydraulic fracturing and the conventional hydraulic fracturing have been presented in these studies. Zang et al. (2017) performed underground fatigue hydraulic fracturing experiments on Ävrö granodiorite at the Äspö Hard Rock Laboratory (HRL) and proved that total number and magnitude of seismic events are found to be smaller in the progressive treatment with frequent phases of depressurization compared to the conventional fracturing case with continuous water injection.
ABSTRACT: It is well-known that the risk of sanding varies for different completion systems, i.e. open hole versus cased and perforation, in a given wellbore and reservoir. Part of this difference comes from the scale effect of the borehole. Pragmatic approaches are usually taken to consider the borehole scale effect in the sand production prediction analysis. A more rigorous approach is needed to take this effect into account.
Experiments have been conducted by researchers on thick-walled cylinder (TWC) samples with different inner to outer diameter ratios (ID/OD) for samples of standard dimensions (1.5 in ID, and 3 in length) to investigate the scale effect on the borehole failure. However, the results partially suffer from the outer boundary effect of the tests and may not purely represent the effects of the inner borehole scale. Here in this paper, the outer boundary effects of TWC experiments were distinguished from the inner borehole scale effect using analytical approaches followed by extensive laboratory experiments. The methodology involves computation and comparison of failure from different criteria (i.e. Mohr-Coulomb, Drucker-Prager, Mogi and Modified Lade) from Tehrani’s results (2016). Then, the volumetric strain was formulated against confining pressure to explain the elastic, elastic-plastic, and plastic behaviour of the rock.
Variation of the TWC strength of samples with different inner borehole sizes may not be fully captured by the analytical approach, which only considers the effect of the ID/OD. Hence, the differences between the analytical and experimental approaches can be considered as the inner borehole scale effect. As expected, the analysis showed that the size of the inner borehole and the outer boundaries significantly change the TWC strength. Surprisingly, the effect of the samples’ OD was obvious, regardless of the corresponding ID. After distinguishing the outer boundary effects, the results show a decreasing trend between the inner borehole size and the TWC strength of the sample, which can be considered as the borehole scale effect.
ABSTRACT: In this study, 3D finite element models are developed to investigate thermally induced stress fields during cryogenic thermal stimulation using liquid nitrogen (LN2). Laboratory tests using LN2 as a fracturing fluid were carried out on concrete, sandstone, and shale samples under confined and unconfined conditions. These tests indicated different fracturing patterns. 3D finite element modeling of the laboratory tests was conducted to predict and analyze the stress behaviors around the wellbore. The combination of laboratory experiments and the 3D finite element modeling provided insight into the potential for cryogenic thermal fracturing in unconventional reservoirs. Three different types of specimen blocks were modeled. These concrete, sandstone, and multi-layer shale blocks were subjected to cryogenic thermal treatments to obtain the temperature and stress profiles and how they are influenced by the formation stiffness. Results show that model developed was successful in simulating the experimental outcomes and observations indicating distribution of high tensile stresses in tangential and longitudinal directions around the wellbore at −321° F. The results of this paper help in understanding the mechanisms of complex fractures created by thermal shock around the wellbore in reservoirs settings.
Cryogenic fracturing is the act of creating fractures by introducing very low temperature liquids into a warmer formation rock under reservoir conditions. This sudden heat transfer will cause the face of the rock to shrink, which will eventually cause the rock to fail in tension (Wang et. al, 2016 and Cha et al, 2014).
King (1983) examined the use of gelled liquid carbon dioxide to stimulate dry gas sand formations. King notes that carbon dioxide returns to the gaseous phase at formation conditions and does not cause sloughing or swelling effects in low permeable water-sensitive formations. In another study, Grundmann et al. (1998) treated a Devonian shale well with cryogenic nitrogen and observed an initial production rate 8% higher than the rate in an offset well that had been stimulated with nitrogen gas. Although the increased initial production rate in this research suggests the efficacy of cryogenic fracturing, there could be a number of reasons why an offset well in a shale formation might produce differentially including anisotropic stress conditions and heterogeneous reservoir conditions over short distances. McDaniel et al. (1997) conducted simple laboratory studies where coal samples were immersed in cryogenic nitrogen. The coal samples experienced significant shrinkage and fractured into smaller cubicle units, with the creation of microfractures orthogonal to the surface exposed to the cold fluid. The researchers found that repeated exposure cycles to the cryogen caused the coal to break into smaller and smaller pieces, becoming rubblelized. If the creation of fractures due to thermal stresses can occur in coal bed formations, it may have the potential to occur in other types of rock as well.
ABSTRACT: In Petroleum, Civil and Mining Engineering, designing structures dealing with rock mass is a day-to-day activity. In order to carry on such projects, it is essential to know the strength and deformability of rocks, as well as their in situ stress state. In Petroleum Engineering, especially, obtaining rock samples from a well and carrying out lab mechanical tests is costly and time consuming. Thus, petroleum engineers have been attempting to determine rock mechanical properties through index tests or log-based correlations as to expedite this process and reduce the global cost of the activity. Besides a comprehensive literature review regarding empirical correlations for predicting rock mechanical properties, this article presents results of uniaxial and scratch tests on a highly heterogeneous limestone sample from offshore wells in Brazil. By comparing UCS results of uniaxial and scratch tests, it was possible to validate the outcomes of the scratch tests. UCS scratch test profile presents a high resolution, in the present work this profile was averaged over intervals around each plug of conventional core analysis. Finally, UCS and Young Modulus empirical correlations for limestones are proposed. Using those correlation one can estimate UCS and static Young Modulus of limestones from their porosities and speed up the MEM assemblage.
The assemblage of a Mechanical Earth Model (MEM) encompasses data gathering and analysis of information regarding in situ stress state, rock properties and underground geometry. An MEM can be seen as a bridge over the gap between Earth Science and Engineering Disciplines. The assemblage of an MEM is, intrinsically, a multidisciplinary task and a team with geologist, geophysicists and engineers must be formed in order to create such models.
A wide range of structural analysis during drilling, completion and production phases can be performed after the MEM assemblage. In reality, an MEM should be used even after the field abandonment, in order to ensure zonal isolation beyond the production lifetime of a reservoir. Depending on local rules, the wellbore seal must last many years beyond the well’s production lifespan. By performing a post-mortem structural analysis of a reservoir, wellbore failure can be predicted and mitigated, avoiding environmental and safety problems.