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This study presents the development and calibration of resistance factors for the serviceability limit state (SLS) condition (φSLS) used in the load and resistance factor design (LRFD) of deep foundations. The performance function was established based on load corresponding to tolerable displacement (Qδtol) and design load (Qd). A dataset of published full-scale load tests including projects from Texas, Missouri, Arkansas, Louisiana, and New Mexico was compiled and consisted of 60 load test cases comprising 33 driven piles and 27 drilled shafts. Resistance factors for SLS conditions were calibrated for tolerable displacements using both the Monte Carlo simulation (MCS) and the First Order Second Moment (FOSM) approaches. From the calibration study, resistance factors at SLS conditions were obtained ranging from 0.33 to 0.62 using FOSM method and 0.37 to 0.67 using the MCS for driven piles. In the case of drilled shafts, SLS resistance factors ranged from 0.37 to 0.77 following the FOSM method and 0.41 to 0.86 based on MCS.

This paper presents a qualitative and quantitative evaluation of the predictive validity of the Texas Cone Penetration (TCP) foundation design method. Allowable loads were determined using both str...

This study analyzes blowcount data from instrumented Texas Cone Penetration (TCP) tests. TCP hammer efficiency, rod length influence on the hammer efficiency, and overburden pressure correction factors for the TCP blowcounts (NTCP) are explored. Results are compared to published correction factors for the standard penetration test (SPT). The final dataset analyzed for this study consisted of 293 TCP tests from which 135 tests were instrumented. TCP hammer efficiency values for automatic trip hammers ranged from 74 to 101% with an average of 89%. Analyses showed a statistically-significant relationship between the TCP hammer efficiency and the rod length below ground surface. Statistical models were developed for undifferentiated soils, and corresponding rod length correction factors for the TCP test (CR-TCP) were obtained ranging from 0.90 to 1.00. In a second analysis, the relationship between the overburden pressure and NTCP was explored and a mathematical expression for the overburden correction factor for the TCP blowcount value (CN-TCP) was determined. This work represents the first study where corrections to NTCP are explored, and the outcome of this research benefits the geotechnical engineering community using the TCP test and its associated foundation design method.

Drilled shafts are increasingly being used for foundation support. The quality of the constructed foundation is critical due the heavy foundation loads and limited redundancy of many drilled shaft foundations. On a recent project in the United States, several traditional and newer methods of quality control and quality assurance were used to assess the drilled shaft excavation, base condition, concrete quality, and capacity. The radii, shape, verticality, and volume of the drilled shaft excavation was evaluated with a SHaft Area Profile Evaluator (SHAPE), and the cleanliness of the shaft base prior to concrete placement was assessed with a Shaft Quantitative Inspection Device (SQUID). The placed concrete quality was evaluated with Cross-hole Sonic Logging (CSL) as well as Thermal Integrity Profiling (TIP). Finally, a bi-directional static load test (BDSLT) was conducted on the test shaft to determine the shaft capacity.

This paper presents a systematic review of existing methods (original, modified, and load-transfer methods) for constructing an equivalent top loading (ETL) curve using the results of O-cell tests for drilled shaft foundations. The authors performed parametric studies using load-transfer analyses to investigate the effects of the slenderness ratio, foundation stiffness, and the stiffness of the surrounding geomaterials on the elastic shortening of the foundation, which is one of the key components when constructing an ETL curve. Results from the parametric study showed that the foundation compressibility increased with an increasing slenderness ratio, increasing stiffness of the surrounding medium, and decreasing stiffness of the foundation material. It was further shown that when O-cell tests are performed on drilled shafts with very high slenderness ratios or drilled shafts with moderate slenderness ratios, but installed in a very stiff medium, the elastic shortening must be taken into consideration when constructing ETL curves. Full-scale load test data from projects with both the conventional top-down and O-cell load tests performed at the same site were collected and used to assess the validity of the existing ETL methods through three case studies. Analyses of the case studies suggested that the differences among the three existing ETL methods were not significant in terms of ultimate capacity. However, in terms of head settlement, the original ETL method yielded a significantly stiffer load-settlement response than a conventional top-down load test. In contrast, ETL curves constructed by the load-transfer method or the modified method were both practically accurate enough to estimate the head settlement under the service load.

Deep excavations associated with the construction of underground parking garages for major corporate buildings create significant challenges for geotechnical engineers, especially when the subsurface material consist of non-controlled fill. This paper provides a detailed description of a project located in Santa Fe, Mexico City, Mexico, where two corporate towers with 26 and 12 stories and 8 basement levels were built on a 1970s landfill site. Based on the maximum depth of excavation and local restrictions on deformations for major road arteries located in close proximity to the project site, the retaining system selected for the project consisted of a diaphragm wall reinforced with post-tension anchors. In addition to geotechnical drilling and sampling, results of three full scale pull-out test completed at the north end of the project site are discussed. From the load tests, cable elongations were recorded to be less than 1% of the bonded length of the anchors.

Knowledge of swelling properties of shale-oil formations as well as the effects of various drilling fluids, including both water-based and oil-based muds (OBMs), which are of critical importance to wellbore-stability problems, requires a better understanding of shale-oil properties. Drilling through shale-oil formations is highly problematic and imposes substantial costs to the operators owing to wellbore-stability problems. These problems include, but are not limited to, tight holes, stuck pipe, fishing, sidetracking, and well abandonment. To more efficiently and effectively drill through these formations, we should better understand their properties. Only few experiments have been conducted on shale-oil samples to better understand their properties. Most experiments performed thus far were run on common shale core samples, which are significantly different from shale-oil samples in the matter of mineralogy and mechanical properties. Subsequently, the results of those experiments cannot be equally applied to shale-oil and shale-gas formations. In this study, we first determined the mineralogy of shale-oil core samples from the Eagle Ford field and then investigated the swelling properties and cation exchange capacity (CEC) of the core samples in the laboratory. Experiments have been conducted with the samples partially submerged in distilled water, potassium-chloride (7% KCl) brine, and OBM. Several experiments have been performed using strain gages to measure lateral, axial, and diagonal swelling in both submerged and non-submerged areas. We also performed unconfined compressive strength (UCS) tests to investigate the effect of the invasion of various drilling fluids on the compressive strength of the core samples. The experimental setup was modified to accommodate five linearly variable displacement transducers (LVDTs) to measure Young's Modulus (E) and Poisson's ratio (v). Various experiments were run to quantify the effect of temperature on the rock compressive strength, E, and v. Experiments have shown a distinct change in the mechanical properties of the rock. The results demonstrate that the swelling properties and CEC of the shale-oil core samples are different from the common shale core samples. This study proposes the quantification of the shale/fluid properties, the interaction, and the effects of different fluids on rock properties in unconventional reservoirs. This paper presents and documents the differences in the swelling properties between conventional and unconventional shale. The results of the study will help us to more precisely understand unconventional shale-oil rock properties and can be used to design a more effective drilling fluid for field applications, as well as more accurately predict the mechanisms of formation failure.

Although many shale oil wells have been drilled in recent years, the industry as a whole is still at the beginning of the learning curve with respect to shale oil drilling operations. Drilling through shale oil formations can be problematic and impose significant costs to operators attributed to wellbore stability problems. These problems include but are not limited to tight holes, stuck pipe, fishing, sidetracking, and well abandonment. Therefore, to more efficiently and effectively drill through such formations, operators should better understand their properties. So far, few experiments have been conducted on shale oil rock samples to better understand their properties while drilling using oil-based mud (OBM). Most experiments have been performed on common shale core samples, which are significantly different from oil shale samples in terms of mineralogy, cation exchange capacity (CEC), pore fluid, and swelling properties. This study investigates the swelling properties and CEC of shale oil core samples from the Eagle Ford field in the laboratory. Specifically, scientists submerged samples in 7% potassium-chloride (KCl) brine and OBM and then used strain gauges and the V-Shay data acquisition system to record both lateral and axial swellings for submerged and non-submerged areas. They then compared the effects of drilling fluid on the swelling properties of the rock samples and, consequently, on borehole stability during drilling operations. All of the experiments were performed in an environmental chamber, which allowed maintaining a constant temperature. The samples were taken from the vertical, horizontal, and diagonal (45°) directions relative to the layering to help determine the optimum well path that would encounter the least possible wellbore stability problems associated with swelling during drilling operations. The results demonstrate that the swelling properties and CEC of the shale oil core samples are different from the common shale core samples. The study quantified the shale/fluid properties, interactions, and effects of the different fluids on rock properties in unconventional reserves. The results of the study can help drilling engineers more precisely understand unconventional shale oil rock properties. The results of the study should also help design a more effective drilling fluid for field applications, as well as more accurately predict the mechanism of formation failure.

Although many shale oil wells have been drilled recently in the Eagle Ford shale oil field, wellbore stability problems in the shale oil reservoirs have not been fully understood. During drilling, fracturing, and production operations, the wellbore temperature is not constant but varies during these operations. This temperature fluctuation results in thermal cycling which tends to alter rock physical properties such as compressive strength, Young's modulus (E), and Poisson's ratio (ν), and consequently, result in wellbore stability problems. Wellbore stability problems are one of the most costly problems that can occur during drilling operations, especially in unconventional reservoirs. These problems include but are not limited to tight holes, pipe sticking, fishing, sidetracking, and well abandonment. Since the majority of wells are drilled horizontally in shale oil reservoirs, the likelihood of wellbore stability problems is dramatically increased. Thus, to have more efficient and effective drilling operations through these formations, a better understanding of their properties as well as the effects of drilling conditions on rock properties such as compressive strength, Young's modulus (E), and Poisson's ratio (ν) are required. Not many experiments have been performed to investigate the effect of temperature on sedimentary rocks' properties such as compressive strength. Some experiments have been conducted to assess the effect of temperature on shale rock samples, since shale oil rock samples are quite different from common shale rock samples, the results cannot be equally applied to shale oil and shale gas formations. For this study, the mineralogy of shale oil core samples from the Eagle Ford field was determined. To simulate actual well conditions a High Pressure High Temperature (HPHT) setup was built and used which let us apply different axial and radial confining stresses, equivalent formation pore pressure, and drilling fluid wellbore pressure. The experiments were conducted under elevated temperatures to better mimic real drilling operations. Saturated shale oil core samples from the Eagle Ford field were tested under various temperatures including reservoir temperature. We also performed Unconfined Compressive Strength (UCS) tests to investigate the effect of temperature on the compressive strength of the core samples. The experimental setup was modified to accommodate five Linearly Variable Displacement Transducers (LVDTs) to measure Young's Modulus (E) and Poisson's ratio (ν). Various experiments were run to quantify the effect of temperature on the rock compressive strength, E, and ν. Experiments have shown a distinct change in the mechanical properties of the rock. These effects will be discussed in details.

In the industry as a whole, we are still at the beginning of the learning curve for shale oil drilling operations; however, many shale-oil wells have been drilled in recent years. Drilling through shale-oil formations is very problematic and imposes significant costs to the operators owing to wellbore-stability problems. These problems include, but are not limited to, tight holes, stuck pipe, fishing, sidetracking, and well abandonment. To more efficiently and effectively drill through these formations, we should better understand their properties. Few experiments have been performed on shale-oil samples to better understand their properties. Most experiments conducted thus far were performed on common shale core samples, which are significantly different from shale oil samples. In this study, we first determined the mineralogy of shale-oil core samples from the Eagle Ford field and then investigated the swelling properties and Cation Exchange Capacity (CEC) of the core samples in the laboratory. Experiments have been conducted with the samples partially submerged in distilled water and potassium-chloride (KCl) brine. Several experiments have been performed using strain gages to measure lateral, axial, and diagonal swelling in both submerged and non-submerged areas. The results demonstrate that the swelling properties and CEC of the shale oil core samples are different from the common shale core samples. This study proposes the quantification of the shale/fluid properties, the interaction, and the effects of different fluids on rock properties in unconventional reservoirs. This paper presents and documents the differences in the swelling properties between conventional and unconventional shale. The results of the study will help us to more precisely understand unconventional shale oil rock properties and can be used to design a more effective drilling fluid for field applications, as well as more accurately predict the mechanisms of formation failure.