bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Radial Bond Segmented Waveforms to Evaluate Cement Sheath at Varying Depths of Investigation
Authors: Frisch Gary , Fox Phillip , Hospedales Dexter , Lutchman Krishna 
Published: September 2015

Abstract
The radial bond tool consists of multiple receivers normally 2 to 3 ft from the source in addition to the standard 3 to 5 ft of receiver spacing. The standard interpretation from these tools consists of 6 to 8 amplitude measurements presented as either curves or as an image, indicating circumferential cement to casing bond. Evaluating bond quality of the annular space between casing and formation has been extremely difficult using existing logging tools and interpretation techniques. The discussed technique processes segmented waveforms in an innovative way, providing additional circumferential cement bond information at varying depths of investigation in annular space.
A new method of interpretation has been applied to the cement bond log (CBL) waveform that examines the peaks and troughs of the waveform to help determine the cement bond between the casing and formation. The interpretation provides up to four different amplitude curves at different depths of investigation in the annular space. Applying the same methodology to the segmented waveforms, but with additional steps, allows the circumferential bond to be determined between the casing and formation. Depending on the length of the segmented waveforms, these annular shells can extend from the casing to the formation, and can be corrected for the relative bearing of the tool.
The example is a standard cement evaluation immediately above and below the surface casing shoe, with a washout immediately below the casing shoe. Both the raw and advanced cement evaluation revealed poor bond in the washout region. With the new processing of the radial waveforms, a channel in the annular space was shown to extend almost all the way to the surface, which is not visible using standard interpretation techniques. Using older standard evaluation techniques, the channel would have been missed or incorrectly evaluated. The use of the radial shell technique provided accurate interpretation of the annular space between the casing and formation.
Standard interpretation of radial bond data does not include use of segmented waveforms. With this new processing technique, not only are the segmented waveforms used, but the annular space is broken into regions or circumferential shells, which can be further evaluated. These shells allow evaluation between the casing and formation, and allow a more accurate and complete evaluation of the cement sheath. This can help provide a more precise assessment of wellbore integrity and help prevent loss of the wellbore attributed to cement and or casing failure.
The Effects of Fracture Orientation and Elastic Property Anisotropy on Hydraulic Fracture Conductivity in the Marcellus Shale
Authors: McGinley Mark , Zhu Ding , Hill A. Daniel 
Published: September 2015

Abstract
Production of hydrocarbons from low-permeability shale reservoirs has become economically feasible thanks to advances in horizontal drilling and hydraulic fracturing. Together, these two techniques help to create a fracture network, which act as fluid conduits from the reservoir to the wellbore. The efficacy of a fracturing treatment can be determined through fracture conductivity analysis. Fracture conductivity is defined as the product of fracture permeability and fracture width, and describes both how much and how easily fluid can flow through fractures. It is therefore directly related to well performance.
The goal of this work is to explore fracture conductivity of Marcellus shale samples fractured in both horizontal and vertical orientations. The Marcellus shale, located primarily in Pennsylvania, Ohio, West Virginia, New York, and Maryland, is the largest gas-bearing shale formation in North America, and its development has significant implications on regional economies, the energy infrastructure of northeast United States, and the availability of petrochemical plant feedstock.
In this work, a series of experiments was conducted to determine the propped fracture conductivity of 23 different outcropsamples from Elimsport and Allenwood, Pennyslvania. Before conductivity measurements were taken, the pedigree of samples was verified through XRD analysis, elastic rock properties were measured and compared against literature values, and fracture surface contours were mapped and measured. Fracture conductivity of both horizontally and vertically-fracture samples was determined by measuring the pressure drop of nitrogen gas through a modified API conductivity cell.
Results show that fracture conductivity varies as a function of fracture orientation only when anisotropy of the rock's mechanical properties is pronounced. It is hypothesized that the anisotropy of Young's Modulus and Poisson's Ratio play a significant role in fracture mechanics, and therefore in the width of hydraulically-induced fractures. Ultimately, the experiments conducted as part of this work show that fracture conductivity trends are strongly tied to both proppant concentration and the rock mechanical properties.
Blowout Prevention and Relief Well Planning for the Wheatstone Big-Bore Gas Well Project
Authors: Upchurch Eric R. , Falkner Sam , House Andrew 
Published: September 2015

Abstract
The offshore Wheatstone LNG Project in Western Australia utilizes subsea big-bore gas wells as the preferred method of producing the field. Wheatstone wells use a 9–5/8” production conduit from the top of the gas pay zone to the ocean floor. Well bores of this size are necessary to match the large productive capacity of the gas reservoirs they penetrate. This producing scenario provides the obvious benefit of yielding large volumes of gas through the use of relatively few wells. Each of those highly productive wells, however, also represents a source of gas that, if accidently allowed to flow unhindered, could present an uncommonly difficult well control challenge. It is for this reason that the Wheatstone Drilling and Completions Team evaluated a wide range of possible reservoir and well architecture scenarios to fully understand the possible scale of relief well responses that might be necessary in the event of a blowout. The conclusions from this evaluation were surprising. Our originally-planned well design concept called for penetrating the Wheatstone gas reservoirs with a casing shoe set 950m vertically above. Our analysis indicated that 3–4 relief wells would be simultaneously required to bring a blowout under control. Based on these results, both the well and the drilling execution plan were redesigned to minimize the number of required relief wells. In summary, the redesign amounted to setting casing immediately (i.e., ≤ 3m) above the gas reservoir before actually penetrating it, with the resulting benefit of reducing the required number of relief wells to 2. Although this reduction is beneficial, it should be noted that there is only one documented subsea case where 2 or more relief wells have been drilled with the intent of simultaneously pumping into both to effect a dynamic kill. Given this fact, our well control-related preparations for executing this project were more extensive than that of preceding projects.
This paper chronicles the full extent of the engineering and operational planning performed to ensure that no uncontrolled hydrocarbon releases occurred during the execution of the Wheatstone Project's subsea big-bore gas wells and, if a blowout were to occur, that the response to such an unprecedented event would be sufficient and robust. Covered in the paper are (1) reservoir deliverability modeling, (2) dynamic kill modeling, (3) gas plume modeling, (4) relief well trajectory and mooring planning, (5) pilot hole execution planning, (6) a newly applied LWD technology for sensing resistivity vertically below the drill bit and (7) a discussion of future research that has been identified as necessary to better define the fluid injectivity capabilities of subsea relief wells.
Packing The Unpackable: How The Use Of Best Sand Control Technologies Reversed The Marginal Project Of Atlanta In A Promising Development
Authors: Pedroso Carlos A. , Liborio Fernando , Rausis Mauro , Moreira Marivaldo , Salies Jacques B. 
Published: September 2015

Abstract
“To produce the most viscous oil from completely unconsolidated sandstone in ultra deep waters”. This summarizes the challenges to construct the wells to exploit the Atlanta field, Santos Basin, Brazil. The ultra deep water of 1550m, the use of a powerful subsea ESP with 1,600 HP, the need of long (850 m) open hole horizontal gravel pack (OHHGP), the low burial depth (800 m) resulting in low reservoir temperatures (100 F) and extremely low fracture gradient (0.50 psi/ft), the highest acidity of a crude (TAN=9.8) are some of the difficulties that had been overcome to drill, complete and test the first 2 production wells of the Atlanta Field.
Atlanta is a post-salt oil field located 185 km off the coast of Rio de Janeiro. The field was discovered in 2001 and during the same year a deviated well was drilled to test the eocenic sandstones. A cased hole gravel pack was installed in 90m of perforated interval. The completely unconsolidated sandstone showed high porosity (36%) and high permeability (5D). While the rock properties are excellent, the oil is heavy and viscous (14° API and 228 cP in reservoir conditions), with the highest acidity registered (TAN=9.8).
In 2006, a horizontal well was drilled to test the full potential of this kind of construction, which included and OHHGP, and to validate the field development concept. However, crucial problems were faced during the drilling and completion phase. Directional control problems led to two sidetracks. The horizontal section experienced massive fluid loss. Only part of the screens was run in the open hole. The attempt to pack the screens, with alpha-beta waves, resulted in a premature screen out leaving a SAS completion. Even after these problems, the well was tested, with solid production causing the ESP failure. The partially conclusive DST showed a severe damaged well, with high skin of 40.
The bad experience in constructing a horizontal well in these challenging conditions compromised the reliability of the project. But in 2012, a new operator decided to revisit this project. After considering technology improvements, an extensive preparation and a complete assessment of past operations were performed. Finally, in 2013 and 2014, 2 wells were drilled and, using the best technologies, 100% packed in the full horizontal length (800m) drilled. Both wells were tested showing zero skin.
This paper presents the main challenges and how they were overcome by using the best sand control techniques, resulting the successful construction, gravel packing and testing the first two production wells, recovering the reliability of the project and encouraging to move on to the next phase.
How Big is Too Big? Assessing Seismic Hazard and Hydraulic Fracture-Induced Seismicity
Authors: Bowman-Young Sheri , Urbancic Ted , Viegas Gisela , Meighan Lindsey , VonLunen Eric , Hendrick Jason 
Published: September 2015

Abstract
A vast number of the reported cases of increased seismicity of moderate magnitude (Mw &gt; 0) earthquakes seem to be tied to some form of fluid injection activitiy, being it wastewater disposal by injection into deep wells or high pressure fluid injection into oil and gas reservoirs to hydraulically fracture the rock and improve hydrocarbon recovery. Regulations have been proposed to implement traffic light systems to dictate the responses that the industry needs to take based on either the magnitudes or observed particle velocities or accelerations on the surface. In order to relate the seismic hazard potential in seismically active areas, empirical ground motion prediction equations (EGMPE) are used to relate event parameters like magnitude and location to site characteristics such as peak ground acceleration (PGA) or peak ground velocity (PGV) which tend to be how building codes are parametrized. Therefore, local hazard assessment near hydraulic fractures that generate relatively large magnitude events need to be estimated more precisely by developing and using local EGMPEs.
Hybrid deployments combining 15Hz downhole and low frequency near-surface geophones can be used to accurately capture both the localized microseismic events and any large magnitude events associated with hydraulic fracture monitoring across North American basins – Horn River, Eagle Ford, Barnett, and Montney for example. In our studies events with M&gt;0 are observed for completions in these formations. While in many cases the magnitude of these events is too small to be felt on the surface, there are reports of higher magnitude events which have been sensed by workers on site and the local population.
The exact relationships between magnitudes and shaking are not necessarily one-to-one. Shaking also varies based on the stress release of the events. As summarized recently by Hough (2014) for other fluid-induced seismicity, the lower stress releases typical for these sequences results in on-average less shaking than is observed for equivalent magnitude tectonic events. In order to quantify shaking over a seismogenic volume, we show how to develop EGMPEs based on the North-American examples. The EGMPE methodology developed in this study can be extrapolated for similar earthquakes of larger magnitude and included into future probabilistic hazard and risk analysis for induced seismicity as related to hydraulic fracture stimulations.
Advanced Modeling of Interwell Fracturing Interference: an Eagle Ford Shale Oil Study
Authors: Marongiu-Porcu Matteo , Lee Donald , Shan Dan , Morales Adrian 
Published: September 2015

Abstract
To investigate interwell interference in shale plays, a state-of-the-art modeling workflow was applied to a synthetic case based on known Eagle Ford shale geophysics and completion/development practices. A multidisciplinary approach was successfully rationalized and implemented to capture 3D formation properties, hydraulic fracture propagation and interaction with a discrete fracture network (DFN), reservoir production/depletion, and evolution of magnitude and azimuth of in-situ stresses using a 3D finite-element model.
The integrated workflow begins with a geocellular model constructed using 3D seismic data, publicly available stratigraphic correlations from offset vertical pilot wells, and openhole well log data. The 3D seismic data were also used to characterize the spatial variability of natural fracture intensity and orientation to build the DFN model. A recently developed complex fracture model was used to simulate the hydraulic fracture network created with typical Eagle Ford pumping schedules. The initial production/depletion of the primary well was simulated using a state-of-the-art unstructured-grid reservoir simulator and known Eagle Ford shale pressure/volume/temperature (PVT) data, relative permeability curves, and pressure-dependent fracture conductivity. The simulated 3D reservoir pressure field was then imported into a geomechanical finite-element model to determine the spatial/temporal evolution of magnitude and azimuth of the in-situ stresses.
Importing the simulated pressure field into the geomechanical model proved to be a critical step that revealed a significant coupling between the simulated depletion caused by the primary well and the morphology of the simulated fractures within the adjacent infill well. The modeling workflow can be used to assess the effect of interwell interferences that may occur in a shale field development, such as fracture hits on adjacent wells, sudden productivity losses, and drastic pressure/rate declines. The workflow addresses the complex challenges in field-scale development of shale prospects, including infilling and refracturing programs.
The fundamental importance of this work is the ability to model pressure depletion and associated stress properties with respect to time (time between production of the primary well and fracturing of the infill well). The complex interaction between stress reduction, stress anisotropy, and stress reorientation with the DFN will determine if newly created fractures propagate toward the parent well or deflect away. The technique should be implemented in general development strategies, including the optimization of infilling and refracturing programs, child well lateral spacing, and control of fracture propagation to minimize undesired fracture hits or other interferences.
Analysis of the Effect of Eccentricity on Displacement of Non-Newtonian Fluids with a Hybrid Method
Authors: Xie Liangjun , Chaudhary Saleem , Chen Zhongming 
Published: September 2015

Abstract
The effect of eccentricity on pressure drop and mud displacement in annular flow is an important topic in drilling and cementing. Most researchers have focused on the effect of pressure drop with eccentricity and pipe rotation in drilling. In cementing, determining the fluid rheology and flow profile is important to the success of mud displacement and cement placement. Most recent researchers have adopted computational fluid dynamics (CFD) models to obtain results with Newtonian, or Power Law, or Bingham Plastic models. However, they are slow in computation and need special software to run, and thus are not readily applicable to the field. Furthermore, there are few results with the Herschel-Bulkley model, which is widely used in the industry. It is necessary to design an algorithm that can predict eccentric pressure drop, fluid rheology and flow profile in the annular cross-section accurately and efficiently.
In this paper, we introduce a novel hybrid algorithm to predict the effect of eccentricity on pressure drop and fluid velocity profile in the annular cross-section. First the pressure drop with concentric wellbore geometry is calculated as an initial guess. Second, similar to CFD and finite element method (FEM), the annular cross-section is divided into small mesh elements. Equations governing the condition must be adapted to the geometry of each mesh element. Third, iterations are executed over pressure drop, fluid velocity, and flow rate in each mesh element until the total flow rate converges. Breaking the gel and critical velocity are important to determine the flow status in the mesh element.
The proposed hybrid algorithm includes the Newtonian, Power Law, Bingham Plastic, and Herschel-Bulkley rheology models. Simulation and job history data are used to investigate the effect of eccentricity on the pressure drop, fluid rheology, and flow status in the annulus. Observations indicate that increasing eccentricity decreases the frictional pressure drop. This matches the results in the literature. We also observed that the fluid tends to remain stationary in regions with a narrow gap, while the wide side may maintain turbulent flow. Normally, laminar and static areas are predominant for typical fluids. In addition to predicting reasonable trends, the hybrid algorithm is efficient and accurate.
A hybrid algorithm has been proposed to investigate the effect of eccentricity on frictional pressure drop and mud displacement in the annular cross-section. It is applicable to the main rheology models, and it works accurately and efficiently. The hybrid algorithm is described along with discussion of results over the typical range of geometries encountered.
Design, Construction and Operation of an Automated Drilling Rig for the DSATS University Competition
Authors: Bavadiya V. A. , Aljubran M. J. , Kibe J. M. , Christy S. M. , Le H. N. , Ahmed R. , Florence F. 
Published: September 2015

Abstract
The Drilling Systems Automation Technical Section (DSATS) is a group of SPE volunteers from many nations, connected by their belief that drilling automation will have a long-term, positive influence on the drilling industry. DSATS implemented a student competition to encourage new entrants into the drilling industry who might consider creating and using automation tools and techniques in future drilling programs. The competition brings a hands on approach to the complex, multifaceted problem of drilling systems, expanding the breadth of knowledge and creative thought processes of the individuals who participate. This project challenges students who plan to become petroleum engineers and other students in related disciplines who may not currently think of the upstream drilling industry as a career opportunity. The competition requires university teams to design and build laboratory-scale drilling rigs to automatically drill through a sample of material unknown to the students. This paper presents the winning students' summary of the rig design, construction and operation of their test results and how it relates to their new understanding of the drilling process.
In the fall of 2014, student teams from different petroleum engineering schools designed a rig that can drill through a concrete block filled with unknown formations while dealing with a drill bit and drillpipe chosen to ensure some common drilling dysfunctions. Based on the rig design, finalists from four universities were selected to move to the second phase of the competition (i.e. construction and testing phase). In the early-spring of 2015, the teams built their rigs. In May and June, they demonstrated the performance of their rig design and control algorithms by drilling the samples while witnessed by DSATS members.. The winning team received a travel grant to attend the ATCE to present this paper that addresses:
Drilling limitations and critical parameters Construction issues and initial operations that required a re-design Final design criteria, constraints, tradeoffs How key decisions were determined Summary of recorded data and key events Drilling parameters and how they impacted the test Economic considerations Significant new team learnings Other items of interest Conclusions and recommendations
We believe this to be the first competition of this kind that requires multi-disciplinary teams to work jointly within a university setting, which prepares them for the integrated team approach currently in use throughout our industry. Their designs are practical, but are not limited by the historical features that are commonly included in today’s commercial rig designs.