bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drillstring Mechanics Model for Surveillance, Root Cause Analysis, and Mitigation of Torsional Vibrations
Authors: Ertas Deniz , Bailey Jeffrey R. , Wang Lei , Pastusek Paul E. 
Published: December 2014

Summary
Vibrations have been identified as one of the most-frequent and persistent performance limiters by limiting weight on bit, rate of penetration, or borehole quality even when they may be low enough not to cause damage to downhole tools and equipment.
A general purpose drillstring mechanics model has been developed to analyze axial and torsional vibrations in the frequency domain and provide vibration indices indicative of dysfunction in these modes. The model uses transfer matrices to solve for harmonic perturbations around a baseline solution obtained from a torque/drag type analysis, and accounts for effects of well path, tool joints, viscous damping caused by the drilling fluid, surface-boundary conditions, bit characteristics, and special vibration mitigation tools. The model supports workflows for real-time vibration surveillance as well as post-drill root cause analysis and well redesign. For example, real-time stick/slip severity monitoring is enabled by use of 1-second surface measurements. As a well redesign tool, a large number of design alternatives can be quickly evaluated to mitigate vibrations.
Case studies using high-frequency surface/downhole drilling mechanics data validated the model and identified three types of torsional dysfunctions with distinct signatures and mitigators: unstable stick/slip, an instability associated mostly with the lowest-frequency torsional resonance of the drillstring; bit/bottomhole assembly stall, which is intermittent, sudden mechanical jamming at the bottom of the drillstring; and synchronous torsional oscillation, which is the amplification of periodic excitations at torsional resonances of the drillstring. In one case study, the stick/slip surveillance tool was superior to real-time downhole measurements in lag time, bandwidth, and accuracy. In another case, the root cause of prevalent unstable stick/slip was identified as velocity-weakening aggressiveness of the bit. Of the redesign options, the use of a topdrive controller tuned to damp out the lowest-frequency torsional resonance was deemed most effective. One such controller was evaluated in the field and was very effective at mitigating stick/slip in subsequent wells.
Drillstring Analysis With a Discrete Torque/Drag Model
Authors: Mitchell Robert F. , Bjørset Arve , Grindhaug Gaute 
Published: December 2014

Summary
The only standard drillstring model in use today is the torque/drag model because of its simplicity and general availability. Field experience indicates that this model generally gives good results but sometimes performs poorly. For example, some friction loads predicted for casing running in horizontal wells have not been consistent with field data.
In the standard torque/drag model, the drillstring shape is taken as the wellbore shape. However, given that the most-common method for determining the wellbore shape is the minimum-curvature method, this assumed wellbore shape forces the bending moment to be discontinuous at survey points. This defect is dealt with by neglecting the bending moment.
A different approach assumes that the drillstring position corresponds with the minimum-curvature wellbore only at discrete points. The obvious choice for these discrete points is at the positions of the tool joints in the drillstring. Although these tool joints are fixed in position, they are allowed to rotate within the wellbore. These extra degrees of freedom allow solution of the bending-moment problem, because continuity of bending moment can now be ensured at each tool joint. This paper gives a complete description of the drillstring calculation. Typical torque/drag problems are studied to compare the two torque/drag formulations. These studies give comparisons in drag forces and torques for the two models, and for the new formulation, the magnitude of the bending moments.
Investigation of Nanoparticle Adsorption During Transport in Porous Media
Authors: Zhang Tiantian , Murphy Michael J. , Yu Haiyang , Bagaria Hitesh G. , Yoon Ki Youl , Neilson Bethany M. , Bielawski Christopher W. , Johnston Keith P. , Huh Chun , Bryant Steven L. 
Published: December 2014

Summary
Nanoparticles (diameter of approximately 5 to 50 nm) easily pass through typical pore throats in reservoirs, but physicochemical attraction between nanoparticles and pore walls may still lead to significant retention. We conducted an extensive series of nanoparticle-transport experiments in core plugs and in columns packed with crushed sedimentary rock, systematically varying flow rate, type of nanoparticle, injection-dispersion concentration, and porous-medium properties. Effluent-nanoparticle-concentration histories were measured with fine resolution in time, enabling the evaluation of nanoparticle adsorption in the columns during slug injection and post-flushes. We also applied this analysis to nanoparticle-transport experiments reported in the literature.
Our analysis suggests that nanoparticles undergo both reversible and irreversible adsorption. Effluent-nanoparticle concentration reaches the injection concentration during slug injection, indicating the existence of an adsorption capacity. Experiments with a variety of nanoparticles and porous media yield a wide range of adsorption capacities (from 10–5 to 101 mg/g for nanoparticles and rock, respectively) and also a wide range of proportions of reversible and irreversible adsorption. Reversible- and irreversible-adsorption sites are distinct and interact with nanoparticles independently. The adsorption capacities are typically much smaller than monolayer coverage. Their values depend not only on the type of nanoparticle and porous media, but also on the operating conditions, such as injection concentration and flow rate.
The Use of Modeling To Enhance the Analysis of Formation-Pressure Integrity Tests
Authors: Alberty M.W.. W. , McLean M.R.. R. 
Published: December 2014

Summary
Formation-pressure integrity tests (FPITs) are used to verify the integrity of cement at a casing shoe, measure the stress state of the exposed formations for well planning and operations, and determine the maximum equivalent circulating density to which a shoe can be safely exposed. Critical decisions on operations are made directly from the results and include decisions about the need for remedial cement operations, maximum mud weights that can be used to drill the next well section, minimum mud weights that can be used to prevent hole collapse, calibration factors for predicting fracture gradients, and the potential need for lost-circulation-mitigation strategies.
The interpretation techniques of the result most frequently focus on the point at which a fracture first starts, the point at which unstable fracture growth begins, or the closure pressure of the fracture when pumping ceases. However, the early pressure-buildup behavior is often overlooked and can provide much insight on the integrity of cement, the point of the start of a fracture, the permeability of the formation being tested, the need for cement remediation, and the potential to increase fracture resistance by use of wellbore-strengthening techniques.
This paper presents a model for predicting early pressure-buildup behavior, discusses how the model can be used to improve the interpretation of FPITs significantly, and provides examples of the application in select wells.
Threat-and-Error Management: The Connection Between Process Safety and Practical Action at the Worksite
Authors: Thorogood J.L.. L. , Crichton M.T.. T. 
Published: December 2014

Summary
High-reliability organizations have five important characteristics: a preoccupation with failure, a reluctance to simplify, sensitivity to operations, resilience, and a respect for expertise. Experience from recent incidents suggests that these qualities may generally be lacking in organizations that manage drilling operations today. Research sponsored by oil-and-gas producers and others has suggested that creating a sense of “chronic unease” in relation to barrier integrity and operation of safety-critical systems, combined with understanding of the psychological issues that create error-producing conditions, will strengthen defenses against major accidents occurring. The question remains as to the best way to embed the necessary skills through teaching, coaching, and assessment and their integration into routine working practices.
Experience from aviation suggests that successful implementation of nontechnical skills needs to be combined with a clearly defined operational framework. Such an operational framework, however, is not widely observed in the drilling community at present. A standardized approach that defines how drilling operations are to be executed, activities monitored, decisions made, or changes managed in a time-constrained environment provides the context in which the necessary individual and organizational skills can be taught. Training needs to address the underlying psychological theory—in particular, cognitive biases—of nontechnical skills to counter threats and errors in the workplace.
The paper summarizes the principles of high-reliability organizations and their contribution to process safety in the context of drilling operations. Then, we describe Threat-and-Error Management, which evolved from aviation-based Crew-Resource Management to produce the levels of safety that today we accept as normal. We introduce operational risk management in drilling as the analogous link with aviation. The paper concludes by illustrating how one can use these concepts in drilling operations to enhance routine risk-management activities, and presents a description of the tools and techniques involved.
The advantage of this approach is that effective nontechnical skills can be observed, coached, and assessed on a routine basis in the workplace. Active use of these methods in everyday drilling operations promotes the essential characteristics of a high-reliability organization by instilling the sense of chronic unease and concern for barrier integrity, thereby reducing the chance of minor anomalies cascading into major accidental events.
Real-Time Casing-Design Optimization: A Case Study in the Use of Managed-Pressure Drilling To Develop an Adaptive Well Design and Eliminate Casing Strings on a Deepwater Exploration Well
Authors: Sugden Catherine , Bacon William , Gabaldon Oscar , Borges José Umberto , Soares Cristiane Maravilha , Falcão José Luiz , Nogueira Emmanuel Franco , Vanni Guilherme Siqueira , Chita Luiz Carlos 
Published: December 2014

Summary
A Petrobras deepwater exploration well is planned to be drilled in water depth greater than 2438 m (8,000 ft) offshore Brazil. As is typical of deepwater wells, it has a narrow drilling window between pore pressure and fracture gradient, requiring many casing strings to reach total depth (TD). Because pressure-related problems are often extremely costly when drilling conventionally in deep water, initial design assumptions were conservative, assuming the maximum pore pressure and minimum fracture gradient for casing-point and pipe selection. As with all conventional casing designs, the resulting pipe has limited capacity to withstand increased burst and collapse loads associated with extending hole sections if the opportunity arises.
Managed-pressure drilling (MPD) enables the development of an adaptive well design by providing three key advantages over conventional drilling: the ability to detect kicks and losses extremely accurately (in gallons, rather than barrels); the ability to rapidly respond to and dynamically control detected kicks and losses by adjusting backpressure on the annulus, keeping kick volumes small; and the ability to perform dynamic pore-pressure and formation-integrity tests. Detecting and responding rapidly to kicks allows for the well to be designed with smaller kick tolerances. Furthermore, by keeping the kicks small, they can be circulated out quickly without requiring conventional, time-consuming well-control operations, which often lead to further hole problems. When this advantage is coupled with dynamic pore-pressure tests and dynamic formation-integrity tests, real-time optimization of casing points can be achieved safely with reduced risk of costly well-control incidents.
The method presented here, applicable to any deepwater well, uses low, expected, and high pore-pressure and fracture-gradient estimates to develop an adaptive casing design for the well. In this paper, kick-tolerance calculations for selecting casing points by use of MPD are defined. The effect of reduced kick-tolerance requirements because of the application of MPD is demonstrated, and an adaptive procedure for real-time design optimization of the well is presented. The method results in decision criteria that identify key depths where casing strings can be eliminated without compromising the ability to reach objective TD. The resulting adaptive casing design will most likely eliminate at least one, and has the potential to eliminate two, casing strings, representing significant cost savings.
Casing Expansion as a Promising Solution for Microannular Gas Migration
Authors: Kupresan Darko , Heathman James , Radonjic Mileva 
Published: December 2014

Summary
The objective of this research was to investigate the potential effect of expandable-casing technology on the cement sheath and remediation of sustained casing pressure (SCP) caused by microannular gas migration. Varying magnitudes of SCP exist in the Gulf of Mexico, where more than 80% of casing strings exhibiting SCP are production and surface casings, representing a great technical, economic, and environmental risk. Situations in which SCP is observed usually result in costly and frequently unsuccessful remediation efforts.
A unique bench-scale physical model was used to simulate expansion of a previously cemented casing under field-like conditions. Experimental measurements obtained before and after low-percentage pipe expansion exhibited improvement of cement/pipe interface. Successful multirate flow-through experiments with nitrogen gas showed the effectiveness of this technique in sealing of microannular-gas-leakage pathways, providing ideal remediation of SCP immediately post-expansion; and after up to 60 days of post-expansion, the seal integrity was intact.
Avoid Pilot Holes, Land Wells, and Optimize Well Placement and Production With Deep Directional Resistivity Logging While Drilling
Authors: Dupuis C.. , Mendoza Barrón V.. 
Published: December 2014

Summary
Landing horizontal wells in a reservoir is a critical task, and the accuracy of the result drives the economics of a well. Except when the geological environment is largely predictable, relying on well-to-well correlation techniques or on pilot holes fails to mitigate important risks in landing most wells. This paper details how a different solution more effectively manages the risks of a landing operation. The deep directional resistivity (DDR) logging-while-drilling (LWD) tool has been in use in dozens of fields around the world. The key features of the technology that play a role in derisking the landing of wells range from the tool hardware (which enables a deep depth of investigation, sensitivity to direction, and a wide frequency range) to the surface interpretation software, which provides real-time automatic multilayer inversion. Applied to a landing in a North Sea field, the DDR LWD service was part of the solution for meeting ambitious field-development targets.
Optimization of Well Placement to Minimize the Risk of Scale Deposition in Field Development
Authors: Hutahaean Junko , Demyanov Vasily , Arnold Dan , Vazquez Oscar 
Published: December 2014

Abstract
Determining an optimal location and configuration of well to be drilled is a critical reservoir development decisions as it can cost millions of dollars and determine the volume of hydrocarbons being produced. This is a very challenging task due to large number of decision variables involved. One important factor to consider in field development is scale deposition. It can cause production problem and reduce hydrocarbons recovered. In the extreme case, it can cause a production well to be abandoned as a result of formation damage in the near wellbore or narrowing of the production tubing. Due to the potential high cost of scale management, scale risk deposition would be an important issue.
The aim of the paper is to optimize the placement of new wells in a field development accounting for the risk of sulphate scale deposition. This scale is formed when sulphate rich seawater, usually used as injection fluid to maintain reservoir pressure, mixes with barium rich formation brines. Multi-Objective Optimization (MOO) is used to find a range of solutions by maximizing oil recovery and minimizing scale risk. Scale risk deposition is modelled by tracking the injected seawater concentration, which acts as a natural tracer, in the produced water from each well. Penalty parameter is introduced in the optimization workflow and quantified by relating the scale risk impact in the reservoir production to scale treatment (bullhead-squeeze) as the mitigation. The study used a modified version of the benchmark reservoir model, PUNQ-S3; the model was adapted to be developed using seawater flooding, and as a result sulphate scale deposition is of a major concern. Particle Swarm Optimization (PSO), a stochastic population-based and gradient-free optimization algorithm, is applied to search over the new well locations and their completion zones in the presence of potential scale deposition risk.
The paper compares a conventional field optimization with objective only to maximize oil production to the one with accounting scale risk as extra information. The paper demonstrates that multi-objective optimization allows us to identify well locations and completion zones with high recovery and yet low scale risk, leading to significant economic benefit in a number of field development scenarios.
Factors Controlling Shale Gas Production: Geological Perspective
Authors: Mallick Monalisa , Achalpurkar Manoj 
Published: December 2014

Abstract
Trapped gas within the matrix and fractures of source rock shales is termed as "shale gas." Geologically, the shale-gas-bearing formations are fine-grained, organic-matter-rich (0.5 to 25%), porous, but impervious sedimentary strata with natural gas trapped in the pores, natural fractures, and/or adsorbed onto the clay surface. The primary factors related to the geology and geochemistry of the formation that govern shale gas production potential would be porosity, permeability, natural fracturing, their original hydrocarbon-generating potential, and the amount of gas still present in the formation. Hydrocarbon-generating potential includes the amount of organic matter originally deposited or the total organic carbon content (TOC), types of source organic matter or kerogen type, thermal maturity and hydrocarbon-generating capacity or gas yield, and the extent of conversion of source organic matter to hydrocarbon. These factors again depend largely on the availability of organic matter, depositional environments, depth of burial, local geothermal gradient, and degree of metamorphism. Hydrocarbon-producing potential further depends on the network of natural fractures, microporosity, adsorption, etc. The impervious nature of shale gas formations requires extreme natural or artificial fracturing (fracture stimulation) to recover commercial quantities of gas. Hydraulic fracturing and horizontal drilling are successful techniques recently used for commercial shale gas production, which depend on geomechanical properties, such as mineralogy and brittleness/ductility of the formation. However, selection of drilling and stimulation methodology requires knowledge of other geological parameters, such as the arrangement of the bedding planes, stratigraphy, natural fracture porosity and intensity, clay content, shale-water absorption, fluid-water sensitivity, shale capillary, shale fractal pattern, shale hydration, gas-shale fracture conductivity, relation of geological features of the formation with regional geological settings, and spacial and temporal variation of reservoir parameters. These parameters govern the direction of fracture propagation, gas recovery rate, and wellbore stability of the drilled well, and also aid in determining base-fluid salinity and fluid-type selection for a fracturing treatment. The aim of this paper is to elucidate the geological processes related to shale gas formations for the development of the proper technology to aid hydrocarbon recovery.
Implementation of Coupled 3D Geomechanics and Discrete Fracture Network (DFN) Models in Field Development Optimisation: A Case Study from Carbonate Reservoir, Abu Dhabi
Authors: Ali Edris M. A. , Haggag Amin M. , Al Benali K. , Shinde A. L. , Ghadimipour A. , Perumalla S. V. , Hartley L. J. , Baxter S. 
Published: December 2014

Abstract
An onshore oilfield in Abu Dhabi has complex faulted structure of early Cretaceous carbonate reservoir. The porosity in these reservoirs ranges up to 25%. These reservoirs are overlaid by dense carbonate which acts as a cap rock. The field has been produced for 35 years with peripheral water and gas injection scheme to maintain the reservoir pressure.
The objectives of this geomechanical study were to verify the impact of in-situ stresses and rock mechanical properties on reservoir performance during production/injection activities, as well as to evaluate the mechanical and hydraulic responses of natural fractures and faults to fluid flow within the reservoir. In addition, evaluation of cap rock integrity and fault seal analyses are also considered as necessary risk assessment inputs for field development program.
Extensive rock mechanics testing program has been carried out on reservoir, the interlay dense and cap rock to quantify the contrast in mechanical rock properties and their response to in-situ stresses. Diverse set of data have been integrated including geological, geophysical, petrophysical, reservoir and drilling data to build robust 1D and 3D Geomechanical models. Natural fractures were characterized using core inspection, image logs and CT- Scans which have been calibrated to production logging (PLT) and well tests. Multi-attribute analysis with inputs from petrophysical, structural and geophysical data has been used to build and calibrate the 3D DFN model.
The developed 3D Geomechanical model was coupled with the 3D reservoir dynamic model in order to predict the changes in total stresses due to reservoir pressure changes. Furthermore, this model was integrated with the 3D DFN model to help understand the impact of production/injection activities on the mechanical behaviour of the fractures, fault seal and cap rock integrity.
This paper discusses the role of coupled 3D Geomechanics and the DFN modeling in evaluating and quantifying the mechanical behaviour of reservoir rock matrix, fractures, faults and cap rock that can influence the decisions on optimum field development planning.