bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Decision Analytic Framework for Autonomous Geosteering
Authors: Rajaieyamchee Mohamad A. , Bratvold Reidar B. 
Published: February 2011

Abstract
One of the objectives of Integrated Operations (IO)1 is to automate the decision-making process in drilling operations. Such automation is essential to improve both decision quality and speed in the complex and data-rich environment of drilling operations.
Over the past decade, the E&P industry has significantly improved its ability to acquire and share large data volumes at unprecedented speeds. The motivation for these investments is to increase value through increased future productions while simultaneously reducing drilling costs. However, utilizing the large data volumes is not always straightforward. Sensor measurements are uncertain because of their reading errors and possible malfunctions, and many sources of data need to be fused to provide decision-relevant information. Furthermore, many drilling operational decisions must be made with very limited time, and this makes evaluating potential alternatives based on the decision criteria by the geosteering team difficult or even impossible. Given these challenges, there is a need to develop efficient processes and tools to automatically support drilling operational decisions.
In this paper, we propose a modular intelligent decision advisor (IDA) framework for supporting geosteering decisions. The first module validates and combines the sensor data to determine the probability of the sensor faults and failures as well as undesired geosteering events. These events may include a dramatic increase in drag friction factors, approaching bed boundaries, tools damage, etc. Failure to detect these events could lead to losing the steering ability and sometimes catastrophic problems. The second module proactively analyzes geosteering hazards and recommends the best alternatives. To perform the sensor validation/fusion and hazard/decision analysis, we suggest the use of influence diagrams, also known as Bayesian decision networks (BDNs).
Developing an IDA can lead to the reduction of human operators from rig-sites, drawing its value from improving the human safety and geosteering efficiency. Implementing IO with its associated technologies such as large volume data transmission and computational capabilities provides the means for this autonomous decision advisor. Our results show that the BDN is a useful and relevant element in the autonomous geosteering decision-making process.
Petroleum Engineer or Energy Engineer: Should We Be Both?
Authors: Battalora L. A. , Graves R. M. , McNeil J. A. 
Published: February 2011

Abstract
Each year hundreds of petroleum engineering graduates enter the oil and gas industry workforce eager to confront the challenges presented by worldwide supply and demand. As industry expands its mission to include clean energy, have we adequately prepared our new graduates to address the complex role of global energy consumption and its impact on the oil and gas industry?
An education model exists at the Colorado School of Mines (CSM) to enhance the undergraduate curriculum in the discovery, production and use of energy. An 18-credit Energy Minor addresses the scientific and technical aspects of energy production and consumption in tandem with economic, environmental and societal impact. In a multidisciplinary environment, students investigate the production, delivery, and utilization of fossil, renewable and nuclear energy as it relates to current and future domestic and global requirements and concerns.
The Energy Minor at CSM involves multiple departments on campus. Students enrolled in the Energy Minor may choose from three curricular tracks: Fossil Energy, Renewable Energy, and General. All students must take an Introduction to Energy course, Energy Economics and Global Energy Policy in addition to courses specifically designed for each track. Additionally, an opportunity exists for students who do not wish to enroll in the Energy Minor to earn special recognition in an Area of Special Interest (ASI). The ASI recognition requires a minimum of 12 credit hours of acceptable course work and 2 additional courses selected from the Energy-related course list.
To meet present and future domestic and global energy requirements, we, as educators, are charged with educating our engineering graduates in the areas of renewable, nuclear and unconventional (energy) fossil-based resources in addition to conventional coal, oil and gas energy sources. The Energy Minor at CSM is a novel educational approach that accomplishes this goal.
Design Tools and Workflows to Mitigate Drilling Vibrations
Authors: Bailey J. R. , Wang L. , Tenny M. J. , Armstrong N. , Zook J. R. , Elks W. C. 
Published: February 2011

Abstract
Design tools and workflows to mitigate drilling vibrations have been developed, demonstrated, and documented for several field drilling applications. This paper provides two new case studies to illustrate how this vibration mitigation methodology may be applied. Dynamic motions of the bottomhole assembly are known to be highly detrimental to the drilling process, resulting in unplanned trips, reduced rate of penetration, shortened bit and tool life, and MWD failures. The utility of the BHA design tool and the associated workflow will be illustrated in the context of how the methods have worked in conjunction with improved operating practices to achieve better drilling performance.
One case study shows how vibrations modeling can be used while drilling is underway to select a better BHA design, when it has been recognized that vibrations are a key performance limiter. Another case study illustrates how the vibrations modeling may be used to choose a preferred BHA design in advance of drilling a well or hole section. This proactive predrill workflow provides for advance planning and alignment with service providers. Both of these case studies illustrate how the method can be used to hindcast field results to understand performance change from one BHA to the next.
Vibrations mitigation through BHA design modification, operating parameter selection, and follow-up surveillance is proving to be highly cost-effective in the operator's "relentless re-engineering" process to reduce drilling costs. These technology applications are now being applied on a global scale.
Efficient Hierarchical Processing and Interpretation of Triaxial Induction Data in Formations with Changing Dip
Authors: Wu Peter , Wang Gong Li , Barber Tom 
Published: February 2011

Abstract
Triaxial induction tools have contributed considerably to the understanding of thinly bedded reservoirs, in which the use of both horizontal and vertical resistivity (Rh and Rv, respectively) reduces the uncertainty in laminated sand petrophysical analysis of hydrocarbon in place. At the same time, existing answer products, based on a windowed 1D inversion, return dip and azimuth of the formation as well as Rh and Rv. The dip and azimuth, however, are constrained to be constants over the length of the inversion window, usually at least 10 ft, and often much longer. For many formations in complex environments, the necessary assumptions for using a 1D inversion are at odds with the actuality of the formation, and the results are of questionable quality.
An inversion based on a homogeneous anisotropic formation model was introduced as part of the oil-based mud (OBM) borehole correction for the multiarray triaxial induction tool. It has been observed that this simple model can give better results in some 3D formations than those from the 1D inversion. The authors have taken this observation and have developed a new zero-D inversion that is divorced from the borehole correction algorithm so it can work in all environments, both OBM and water-based mud (WBM). This new process has been implemented in a hierarchical manner with a second-generation 1D inversion algorithm to produce a workflow that allows the best estimates for dip, azimuth, Rh, and Rv in complex reservoirs with changing dip. The results from the zero-D inversion are used to identify the complexity of the formations. The 1D inversion is run or displayed only through those zones in which the 1D model is valid, namely beds with relatively constant dip and azimuth. This new workflow combines the results from both the zero-D and 1D algorithms to produce the best results. Tests with model data of fully 3D formations show that this hierarchical processing workflow returns better results than those from the 1D inversion alone without the guidance of the zero-D inversion.
The results in several complex reservoirs illustrate the applicability of the new algorithms and workflow. Backed by the new process, we expect the triaxial induction measurements to become routinely used in a wide variety of formations.
First Rotary Steerable System Drilling With Dry Air is Used to Further Improve Low Cost Development of an Unconventional Gas Reservoir
Authors: Wilhide Scott , Doebereiner Dan , Smith Jeremy , Raymond Brad , Weisbeck Denis , Ziemke Brian 
Published: February 2011

Abstract
This paper presents the first use of a Rotary Steerable System (RSS) using air as the drilling fluid. The case history is in an ongoing unconventional gas development in the Appalachian Basin of the northeast United States. The RSS has been integral to increasing lateral lengths and corresponding increases in production while reducing development costs. Since 2006, EQT Production has developed Devonian reservoirs in Kentucky, Virginia and West Virginia using underbalanced, horizontal drilling techniques. The low (200-500 psi) bottom hole reservoir pressure does not allow drilling with fluid. Typical horizontal wells have had 3,000 ft laterals drilled with air, positive displacement motors, and electromagnetic telemetry (EM) MWD systems; that remains the predominate drilling technique. The air compatible RSS was employed to increase lateral length and production.
Well 568478, in Letcher County, Kentucky became the first well to have a horizontal section drilled underbalanced using RSS with dry air. To date, eight wells have been drilled with lateral lengths from 3,800 -6,000 ft. Preliminary results show that the reserves developed are proportional to the lateral length drilled. The rates of penetration (ROP) with the RSS in the additional footage were similar to or greater than those in shorter laterals drilled with a motor.
The RSS, with an integral EM MWD, has proven to be a technically feasible option in air drilling environments. The comparable ROP and resulting lower lateral costs per foot achieved with the RSS allows drilling horizontal wells with air beyond their previous limits, enabling greater production footage from fewer wellbores. It further allows drilling portions of the reservoir previously unreachable due to surface constraints such as topography.
Many of the learnings to implement the RSS technology also applied to the use of the positive displacement motors (PDMs) previously used. These learnings were applied to the motors and significant improvements were made in drilling horizontals with these tools. Motor capability was pushed beyond limits previously established in the areas being drilled.
As a result of the success with RSS and PDMs on extended laterals, EQT Production is extending the lateral length from 3,000 ft to 5,500 -7,000 ft on a plurality of the future wells drilled in the Devonian section.
Evaluation of Time to Flow Stabilization and Effective Drainage Area of Slow-Stabilizing Wells Using Production Decline Analyses
Authors: Poe B. D. , Poston S. W. 
Published: February 2011

Abstract
Estimation of the reservoir drainage area, hydrocarbons-initially-in-place, and the production time required for the onset of reservoir boundary effects to be exhibited in the production performance of low permeability reservoirs is of great interest and concern for reservoir and production engineers, reserves analysts, financial institutions, and investors. More generally, it has been observed historically that extrapolation of the results of decline curve analyses of the early transient production performance of oil or gas wells in slow-stabilizing reservoirs can result in tremendous estimation errors of these important reservoir parameters.
Reservoirs that can require a long production time to achieve stabilized boundary-dominated flow may be low permeability, heterogeneous, layered, or naturally fractured. Examples of well completion types that can also result in long production times before flow stabilization are hydraulically fractured or horizontal wells. This paper presents a decline curve analysis technique that can be used to improve the estimation of the reservoir effective drainage area, initial-fluids-in-place, and production time for the onset of boundary effects to be observed in slow stabilizing oil or gas wells.
Model to Predict CO2 Leakage Rates Along a Wellbore
Authors: Tao Qing , Checkai Dean , Huerta Nicolas , Bryant Steven L. 
Published: February 2011

Abstract
Large-scale geological storage of CO2 is likely to bring CO2 plumes into contact with a large number of existing wellbores. The flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. The leakage pathway in wells that exhibit sustained casing pressure (SCP) is analogous to the rate-limiting part of the pathway in existing wellbores along which CO2 may leak. Thus field observations of SCP can be used to estimate transport properties of a CO2 leakage pathway. We develop a more robust optimization algorithm to get the best data fit in the SCP model. Constraints from well construction geometry and from physical considerations reduce the range of estimated permeability. We then describe a simple CO2 leakage model. The model accounts for variation in CO2 properties along the leakage path and allows the path to terminate in an unconfined (constant pressure) exit. The latter assumption provides a worst-case leakage flux.
Using pathway permeabilities consistent with observations in SCP wells, we obtain a range of CO2 fluxes for various boundary conditions. In leakage pathways corresponding to the slow but nonnegligible buildup of casing pressure, the CO2 fluxes are comparable to naturally occurring background fluxes observed at ground surface. In pathways corresponding to rapid buildup of casing pressure, the fluxes are comparable to measurements at Crystal Geyser (Utah), a natural CO2 seep. Uncertainty in pathway permeability has a first-order effect on uncertainty of CO2 flux. Uncertainty in the length of the pathway has a comparatively minor effect. Increasing the CO2 at the base of the pathway does not dramatically increase the CO2 flux above the purely buoyancy-driven value.
Wellbore Dynamics of Carbon-Sequestration Injection - Well Operation
Authors: Mireault R.. , Stocker R.. , Dunn D.. , Pooladi-Darvish M.. 
Published: February 2011

Abstract
This paper uses the experience gained over the past 13 years in analyzing and modeling wells that inject mixtures of hydrogen sulphide and carbon dioxide from sour gas plants to model the operating performance of injection wells for long term CO2 sequestration from electrical power plants. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behavior with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore.
As the world embarks on large scale capture and injection of CO2 emissions from electrical power plants, understanding the operating characteristics of the injection well(s) will be critical to the design, construction and operation of these systems. Unlike water injection wells, increasing the injection rate for a CO2 well does not necessarily increase its wellhead operating pressure. A methodology to estimate wellhead operating pressures is a key requirement for the proper design of the injection wells and the CO2 surface facilities. It may also help engineering and operations personnel, as well as regulatory agencies to understand the complex behavior of CO2 injection wells.
Pressure gradients in aquifers or reservoirs suitable for CO2 sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 103m3/d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, CO2 stream composition and wellhead temperature on wellhead pressure. Depending on conditions, the CO2 stream may undergo phase transitions from a gas or liquid at the wellhead to dense phase fluid in the wellbore and back to gaseous or supercritical out in the reservoir. The complex interactions between phase behavior, fluid density and pressure can lead to unexpected operating characteristics, including an increase in injection rate or sandface pressure with little or no change in wellhead injection pressure.
Modeling CHOPS Using a Coupled Flow-Geomechanics Simulator With Nonequilibrium Foamy-Oil Reactions: A Multiwell History Matching Study
Authors: Rivero Jose A. , Coskuner Gokhan , Asghari Koorosh , Law David H. , Pearce Andrew , Newman Robert , Birchwood Richard , Zhao John , Ingham Jon 
Published: February 2011

Abstract
Cold Heavy Oil Production with Sand (CHOPS) has been widely and successfully applied for the last three decades in the Heavy Oil Belt region that straddles the provinces of Alberta and Saskatchewan in Canada. As its name suggests, the method relies on continuous production of sand to improve the recovery of oil from the reservoir. In CHOPS, a significant pressure drawdown around the wellbore is created by using progressive cavity pumps, which causes the loosely consolidated formation to fail, creating increased permeability channels, usually called wormholes, through which, a slurry-like mixture of sand, oil and water flows.
Many attempts have been made to use conventional numerical reservoir simulators to model the CHOPS process. However, many of the commercial finite-difference reservoir simulators do not incorporate capabilities to model the complex geomechanical processes responsible for the failure of poorly consolidated formations in CHOPS. To circumvent these limitations, several approaches have been proposed. The most common relies on explicitly defining high permeability channels that radiate from the producing wells in an attempt to mimic wormholes created during CHOPS production.
In this paper, we present a different, more rigorous approach that relies on the coupling of a finite-element geomechanical simulator with a finite-difference reservoir simulator. In the coupling process, the geomechanical simulator uses the pressure gradients calculated by the reservoir simulator to determine changes in the stress regime of the reservoir. In the case of CHOPS, these changes cause failure in the loosely consolidated formation, which in turn induces sand production with a corresponding increase in porosity and permeability. The new porosity and permeability values in the affected gridblocks are then fed back to the reservoir simulator, which is now capable of incorporating the effects of formation failure into fluid flow calculations. This process is then repeated at user-controlled intervals during the course of the simulation. The methodology has been validated by successfully history matching the production data from a section of a heavy oil field operated by Husky Energy in Western Canada. In this paper we compile the data integration efforts to create a coupled geomechanical model and the results of the history match.
Proppant Selection and Its Effect on the Results of Fracturing Treatments Performed in Shale Formations
Authors: Terracina J. M. , Turner J. M. , Collins D. H. , Spillars S. E. 
Published: February 2011

Abstract
Since the introduction of hydraulic fracturing, the industry has been attempting to establish laboratory testing parameters that assist operators and service companies in their effort to select the optimum proppant for a particular field application. An example of this effort is the development of the "long-term baseline conductivity laboratory test" for proppants. While this test is a huge leap forward in subjecting proppant to simulated downhole conditions, it still does not adequately address many additional factors that can impact the effectiveness of the proppant such as:
Proppant fines generation and migration in the fracture Proppant resistance to cyclic stress changes Proppant embedment in the fracture face Proppant flowback and pack rearrangement in the fracture Downhole proppant scaling
Most proppant choices are currently based on which one has the highest baseline conductivity, cost, and availability. While this approach seems logical, it runs the risk of overlooking or under-valuing other critical factors effecting proppant performance in downhole environments.
To better define what constitutes the most effective proppant for a particular application, field cases will be presented that focus on the impact of proppant selection in a number of wells completed in various shale formations. The analysis will examine the production history associated with a variety of proppant choices. In an effort to better understand the production results, a series of lab tests will be performed on the proppants utilized in the field cases. These tests will attempt to establish how these factors (such as proppant fines, cyclic stress, embedment, proppant flowback, and scaling) could be used to explain and support the results of the field cases.
Discrete Modeling and Simulation on Potential Leakage through Fractures in CO2 Sequestration
Authors: Huo Da , Gong Bin 
Published: February 2011

Abstract
Natural or injection induced fractures, and abandoned wells with no complete seals are the main sources for CO2 leakage after sequestration. Based on research from various scientific studies, pilot CCS programs and commercial CCS projects, formations and/or cap rocks with fractures may have significant leakage problems thus degrade CO2 sequestration results. Modeling and Simulation of CO2 flow in fractured systems is crucially important for CO2 storage location selection and leakage risk evaluation.
With continuous improvement in fracture characterization, Discrete Fracture Modeling (DFM) is becoming more and more widely used as it can effectively resolve the fracture geometry with much less cells. Recent works from Gong et. al have presented successful application of DFM to large-scale compositional simulations for a gigantic carbonate reservoir. In this work, DFM work flow is applied for simulations on CO2 sequestration for the first time. Fractures are represented explicitly and individually as planar surfaces under an unstructured grid system. Transmissibility between each pair of adjacent cells is calculated and flow simulations are performed by a general connection-list based reservoir simulator.
Several examples including several 2D systems with or without fractures and a system with strong capillary pressure effects are demonstrated. Simulations on systems with fractures in CO2 injection formation versus in cap rocks are compared. Results have shown that the existence of mudstone layers could prevent injected CO2 from leaking outside the aquifer when no fractures are present. While vertical fractures intersecting with mudstone layers will cause significant leakage increase as the fractures form extremely preferential pathways for CO2 transport. Capillary forces also enable us to store CO2 in target aquifer for a long timeframe as it could help trap the residual phase CO2. In comparison with conventional simulators using structured grids, this work provides typical speedups of 3-10.