bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Tower Motion on Packing Efficiency
Authors: Cullinane J. Tim , Yeh Norman , Grave Ed 
Published: September 2011

Abstract
This work reviews the major published studies, both theoretical and experimental, that address the impact of wave motion on packed tower performance. Current practice is to add excess packing to guarantee the required separation is obtained, though there is little data available to derive a safety factor for packing height. This work highlights deficiencies in the current knowledge base and analyzes general trends to address common misconceptions about tower design for floating production.
Tilt and motions imposed on a fractionation column have a significant impact on product specifications due to reduced packing efficiency. Improved awareness of motion impacts will assist the analysis of tower design and allow feedback to the process design. Identifying gaps in available data shows limits in the current understanding and allows the development of appropriate simplifying assumptions.
The current understanding of towers in motion allows only very basic design rules and the safety factor for packing height in literature varies from 1.1 to 2.0. This provides little confidence in the ability to predict packing efficiency for floating production.
Static tilt is more detrimental to liquid distribution than motion at a given amplitude. Still, liquid maldistribution from motion approaches that of static tilt as the period increases. Liquid sloshing, often cited as a significant concern, is a relatively minor contribution to maldistribution except for short periods and tall towers. The relative bed size has a significant impact on liquid maldistribution, limiting the recommended maximum bed height:column diameter to 2 – 3 to maximize the efficiency.
Approach to equilibrium is often overlooked as the major determinant of sensitivity of efficiency to maldistribution. Separations that operate near equilibrium are more sensitive to maldistribution than services with a large driving force. Thus, distillation towers are generally more sensitive to motion than absorbers and sensitivity may vary over column height. Recommendations are provided for a bed-by-bed analysis and feedback to the process design.
Floating production units require additional complexity and conservatism in tower design. An improved awareness of motion effects on towers, and the factors involved, will lead to improved designs and a reduction in the cost of floating production facilities.
Deepwater Multiphase Liquid Sampling Using Multiple Application Reinjection System (MARS)
Authors: Hall G.. , Gordon A.. 
Published: September 2011

Abstract
This paper provides an overview of a new methodology of capturing a physical sample of produced fluid from a Subsea Tree or Manifold in deep water and recovering it for laboratory analysis.
It describes both the sampling & recovery equipment, together with the associated intervention technology, MARS (Multiple Application Re-injection System). The MARS system allows a coaxial flowpath to be introduced into the wellstream without having to recover permenant subsea infrastructure.
Being able to take liquid samples from individual wells subsea before they are comingled into the pipeline enables production optimisation on a number of fronts including:
Flow-meter calibration (affected by water cut / salinity). Tracer detection (understanding the reservoir) Need for Scale squeeze (barium content) Well fluid composition (per well)
The interface technology has already been tested on other deepwater subsea applications, including multiphase pumping, metering and well stimulation. The sampling technology is now proven following testing at the National Engineering Laboratory, East Kilbride, Scotland using both the multiphase and wetgas flow loops. The testing program validated the technique, optimised the design and determined the operating envelope across a wide variety of flow conditions.
Application engineering is underway for a project in the Gulf of Mexico.
The system provides access to valuable data which can be used to optimise production.
Planning and Conducting Well Tests in Deep and Ultra-Deep Water to Mitigate Potential Risks and Justify Expense for the Operator
Authors: Wendler C.. , Maia C. Tigre 
Published: September 2011

Abstract
Well testing is a critical part of potential production assessment in deep and ultra-deep water well development. When target reservoirs produce heavy oil, gas, and condensate, or are high pressure/high temperature (HP/HT) environments, test designers in the operating company must not only focus on safety and risk mitigation for the operator, when planning these tests, but also must assure that the tests will gather enough data to justify the operational expense and potential risks inherent to these types of environments.
Deep-water production usually requires prolonged periods of low temperature and heat loss, which can affect production or result in hydrate formation. Intervention can be problematic and costly. Fluid volumes, well and water depths accessed can increase well-control time and expense for the operator. Also, since these well tests are conducted from mobile vessels, the alarm and subsea equipment philosophies are critical to the enhancement of safety and risk mitigation. Well-test design and string configuration must have flexibility but still must be capable of efficiently controlling the conditions listed above.
Obviously, these and many other issues must be fully understood by the operator if the program plan, equipment, and methodology have the capability to assess the challenges, ameliorate the risks, and provide contingencies for unexpected events that could occur.
This paper explores these issues as well as appropriate methodologies for mitigation. The merits and limitations of various solutions will be considered along with the basic philosophy of equipment consideration. Lessons learned from actual cases will be used to compare consequences of inadequate preparation to the benefits of proper design.
Also explained will be why particular methods and equipment should be used and why others are less desirable. Lessons learned and their application will be discussed, including:
Red, yellow, or degraded status decision making during dynamic-positioning (DP) vessel testing Coiled-tubing usage criteria Defining cushion-type criteria Defining mud-type criteria Hydrate prevention and mitigation Importance of obtaining dynamic reservoir data efficiently and economically without risking the environment and personnel safety.
Meeting the Environmental Challenge with Technology
Authors: Morrison Pete 
Published: September 2011

Abstract
All industries are being challenged to demonstrate corporate and environmental responsibilities, none more so than those of our own sector. We have taken a holistic approach to this challenge by developing waste monitoring systems to support the drilling waste processing service. For the first time, customers can now monitor their drilling waste online with near-real-time data on locations, tonnage, analysis and cumulative costs, thereby ensuring accuracy and regulatory accountability at all times.
Seamless integration of multiple existing IT and drilling and evaluation analyses systems provides cradle-to-grave monitoring and traceability of drilling related waste. This enables waste-processing staff, customers and regulatory bodies to have full visibility of wastes at various stages in the waste-management process, not only from the environmental perspective but also the estimated costs of processing. The customer can now make informed decisions while drilling to reduce the environmental impact and cost of processing the drilling waste.
The integration of existing systems and common data standards such as WITSML delivers an innovative technology solution to the waste-management process and a model for utilizing multiple existing systems across the enterprise, reducing implementation costs and the resource footprint.
By having this high level of visibility to locations, tonnages, analysis results and cumulative cost tracking, the information reconciliation and confirmation of by-product inertness protects both the environment and our customers.
Our challenge has been to elevate the industry's environmental visibility of their waste products to a new level. This will benefit our customers by satisfying the most stringent environmental protection agency requirements. Customers will have a clear chain of custody for their wastes and at the same time lay the benchmark to take them into a future of ever-tightening industry regulations and environmental awareness.
Mechatronics Technology in Drilling Operations Used to Enhance Safety
Authors: Karnugroho Ardia , Nas Steve , Toralde Julmar Shaun , Prajogo Tutuko 
Published: September 2011

Abstract
According to Wikipedia, "mechatronics" is the synergistic combination of mechanical engineering, electronic engineering, computer engineering, control engineering, and systems design engineering in order to design, and manufacture useful products. The combination of these technologies is now actively being used to enhance the safety of drilling operations.
This paper presents an overview of how mechatronics is now used in the oil & gas industry to significantly enhance the safety of drilling operations. In the drilling industry this technology is known as managed pressure drilling.
Automating the control of bottom hole pressures whilst drilling the well significantly enhances the safety of the drilling operation. Using control technology combined with accurate sensors and additional equipment when drilling provides an unprecedented level of detection and control of the well whilst it is being drilled. This in turn enhances the efficiency and safety of the drilling operations.
This technology has been used on a number of high pressure high temperature wells and it is now being used on deepwater wells to provide early kick detection as well as riser gas handling.
This paper demonstrates the use of mechatronics in the drilling process and the applications of managed pressure drilling in deepwater and high pressure wells.
Transforming a Digital Reservoir System into Reality: How to Get Things Right
Authors: Castillo D. A. , Bratovich M. , Early R. 
Published: September 2011

Abstract
The geophysical, geologic, engineering and operational data that makes up the digital spectrum of information in the energy industry certainly has value when analyzed within its respective discipline. Elevating this value to create attainable dividends in the context of the overall reservoir development will depend upon our relentless commitment to integration. This will be especially important as the targeted reservoirs become more complex, volumes smaller, environments more challenging and our need to intervene to enhance production becomes an integral part of field management.
An incomplete or incorrect understanding of the earth model (reservoir and overburden) can result if we fall short in utilizing all data gathered, or ignore or incorrectly interpret the information at hand. This is especially true in today's world of lean resourcing strategies and pressures of reduced decision cycles times. The value of integrating and rigorously interpreting the wide range of data collected from modern technologies and optimizing or automating the workflows can become a measured reality that serves to maximize reservoir performance during a field development program.
As scientists and engineers who are charged with responsibly exploring and exploiting earth's resources, understanding the geomechanical and flow dynamics and petrophysical rock character existing over the entire life-cycle of the reservoir, especially during production and field rejuvenation, positions us to better use modern drilling and completion technologies for optimal well planning and reservoir drainage. Constraints on how the reservoir, overburden, faults and natural fractures behave in time and space will be directly linked to how well we have integrated our data to understand the reservoir and how well we execute a fine-scale production monitoring program.
Integrating this expected influx of digital information will require an industry-wide paradigm shift in how we manage, evaluate and interpret information. The purpose of this paper is to use case studies to describe the critically important role geomechanics, petrophysics and reservoir performance analysis plays in an integrated interpretation with the intent to develop and execute effective management strategies.
A New Method of Acquiring Open Hole Logs in Unconventional Wells
Authors: Reischman Richard L. 
Published: September 2011

Abstract
Open hole logging of highly deviated and horizontal wells is now becoming more accepted due to a recently developed conveyance and acquisition system that can greatly reduce the cost and risk associated with running logs in these types of wells. Conventional log measurements including resistivity and porosity, which in many cases may not have been previously economical to obtain in lateral wells, can now be used to delineate the needed basic reservoir properties for planning completions and future drilling designs.
The method employs a newly engineered ultra slim toolstring that is designed to pass through the drill pipe and a specially designed hollow PDC bit into open hole. Data can then be obtained beyond the bit in memory while tripping out with the tools on pipe. Lost in hole risk and the higher cost of using other more expensive methods, such as LWD, can be minimized by using the drill pipe and bit to safely acquire the data and retrieve the tools if necessary. Circulation of the well fluids and pressure control can still be maintained throughout this process. A brief overview of the conveyance method and acquisition tools will be presented along with log examples from some of the common unconventional plays that outline the applications of this data.
Global Model for Fracture Falloff Analysis
Authors: Marongiu-Porcu M. , Ehlig-Economides C. A. , Economides M. J. 
Published: September 2011

Abstract
Hydraulic fracturing is undeniably the crucial technology involved in the development of tight and/or unconventional gas reservoirs. The fracture geometry and pumping execution, as well as the well architecture, can be designed to maximize the well productivity, provided the reservoir permeability is known. Because it is difficult to estimate permeability from conventional pressure transient tests, various authors have shown how fracture-injection/falloff tests designed for final fracture design calibration (i.e. estimation of closure stress, leak-off coefficient and fracture fluid efficiency) can be used to estimate reservoir permeability as well.
This paper presents a new comprehensive model for the analysis of fracture falloff, following a step-rate or constant rate injection test. The derivative of the falloff pressure change with respect to the logarithm of superposition time shows a progression of straight trends that include a newly introduced elastic closure-dominated flow enabling determination of the closure stress (3/2 slope), post-closure formation-linear flow (1/2 slope) and infinite-acting pseudo-radial (0 slope). This model provides a robust complete assessment tool that allows quantification of all fracture parameters (closure stress, fracture extent, leak-off coefficient and fracture fluid efficiency) as well as reservoir permeability, provided that enough time is allowed for the falloff to reach pseudo-radial flow regime. Both oil and gas reservoirs can be effectively evaluated.
While the approach is leveraging well-accepted pressure transient analysis methods, the inclusion of elastic closure-dominated flow is new. This model can be used to design fracture-injection/falloff tests that would allow determination of all the involved parameters, including reservoir permeability. Field data validate the model and demonstrate the value of this approach.
Rate-Normalized Pressure Analysis for Determination of Shale Gas Well Performance
Authors: Song Bo , Ehlig-Economides Christine 
Published: September 2011

Abstract
The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. However, to improve the well design it is important to quantify the reservoir permeability and the extent of the stimulated reservoir volume (SRV) defined by the created hydraulic fractures.
Rate-normalized pressure (RNP) is easily computed from production data and is more straightforward to interpret than pressure normalized rate. Pseudolinear flow before pressure interference happens between two adjacent transverse fractures, seen as a ½ slope trend in the RNP derivative, and pseudo pseudosteady state, seen as a straight trend with slightly less than unit slope, are key to the analysis. When only pseudolinear flow appears, a minimum extent for the SRV is indicated as well as a maximum value for the shale permeability. The appearance of pseudo pseudosteady state flow provides an estimate for the pore volume of the SRV and a minimum value for the shale permeability. When both pseudolinear and pseudo pseudosteady state flow regimes appear, permeability and the average half-length and spacing of created fractures can be estimated.
We illustrate the analysis procedure with field data from key shale gas plays. Estimates for both the expected ultimate recovery and recovery efficiency as a fraction of the gas in place in the SRV are possible using this interpretation technique. Sensitivity of the analysis to uncertainties in shale thickness, porosity, and adsorption parameters are explored.
Holistic Drilling Fluid and Waste Management in the Fayetteville Shale
Authors: Mabile Mark , Garner Steven , Broussard Barry , Smith Richard 
Published: September 2011

Abstract
Successful application of a Holistic Fluid Management (HFM) program increased drilling fluid performance and reduced waste and costs in Southwestern Energy's (SWN) unconventional Fayetteville Shale gas project in Arkansas from January 2009 through December 2010. The HFM program significantly reduced environmental impact by lowering drilling waste volumes nearly 45 percent, while reducing drilling fluid and waste costs 36 percent. Reduction in Combined Costs (fluid systems, solids control equipment and waste disposal) totaled $69 million while drilling 705 wells with oil-based mud (OBM) over 4,200,000 ft during the 24-month study period.
The holistic management of drilling fluids, solids control, waste management and disposal of drilling waste has been the subject of considerable effort over the last decades. The process required to manage these projects has been well documented, along with successful case histories.
HFM projects have an improved chance of success when expectations, goals, and responsibilities are well-defined, communicated, and understood by all participants. The financial objectives of the providers of fluid-related services may not always align with those of the operator. This hurdle is further complicated by the limited availability of seasoned well site service personnel with the knowledge, authority, and experience to be proactive while implementing the required changes.
Critical components of an effective HFM program are an unbiased and dedicated project team, and the development and communication of the right goals and key performance indicators (KPIs).
Shale Gas-in-Place Calculations Part II — Multi-component Gas Adsorption Effects
Authors: Hartman Robert C. , Ambrose Ray J. , Akkutlu I. Yucel , Clarkson C. R. 
Published: September 2011

Abstract
Recent studies have shown that shale gas industry is incorrectly determining gas-in-place volumes in reservoirs with a large sorption capacity by not properly accounting for the volume occupied by the adsorbed phase. Scanning electron microscopy has discovered nanopores in organic-rich shale with sizes typically in 3–100 nm range; adsorption data show presence of smaller pores and micropores (&lt; 2 nm) as part of the predicted pore size distributions. At pore diameters of this scale the adsorption potential is high and thus the fractional pore volume occupied by adsorbed gas is often substantial. Hence a portion of the total pore volume would be occupied by the adsorbed gas and not available for the free gas molecules. In SPE 131772 a volumetric method, which accounts for the pore volumes occupied by the adsorbed and free gases, has been proposed based on single-component Langmuir adsorption model. In SPE 141416 we recognized the importance and impact of multi-component gas adsorption potential and adsorbed gas density when calculating gas-in-place estimates. We combined the widely used yet thermodynamically inconsistent Extended Langmuir model with volumetrics and free gas composition to formulate a new gas-in-place equation that accounts for the pore space taken up by a multi-component adsorbed gas phase. This paper extends the discussions on the adsorption layer effect of multi-component natural gases. The approach is based on thermodynamically-consistent ideal adsorbed solution (IAS) model to accurately predict adsorbed gas storage capacity for gas mixtures. We expanded on our previous work, where we calculated single-component adsorbed-phase density using molecular modeling and Monte Carlo simulation methods, and propose a new equation-of-state-based analytical approach to predict the adsorbed-phase density of a mixture. In concert, the model improves accuracy of the gas-in-place equations needed to account for the pore space taken up by a multi-component adsorbed phase. The new method yields total gas-in-place predictions, which suggest that an adjustment is necessary in volume calculations, especially for gas shales with high C2+ composition and high in total organic content. The new method is therefore recommended for shale gas-in-place calculations.
Using Moment Tensors to Determine the Effectiveness of Hydraulic Fracture Stage Spacing
Authors: Prince Marc , Baig Adam , Urbancic Ted , Buckingham Katherine , Guest Alice 
Published: September 2011

Abstract
Hydraulic fracturing is performed in tight gas shales in order to create extensive fracture networks throughout the reservoir. Often the distance between injection zones is selected in order to maximize the fracturing of the reservoir and minimize the amount of reservoir that remains untreated. Recently, the deployment of three dimensionally distributed geophone arrays allows for Seismic Moment Tensor Inversion (SMTI). Using SMTI, the rock failure mechanisms can be examined both spatially and temporally, showing how the hydraulic fracture treatments interact with each other.
When events from a hydraulic fracture stage grow into previously fractured zone, there are three possible interactions: the fracture network in the previously fractured zone can dialate; the fracture network in the previously fractured zone can experience equal opening and closing result in little to no increase the effective fracture network; or the previously activated fracture network can experience more closure than opening, resulting in reduced productivity in the reservoir. One parameter that can be calculated from the SMTI is the cumulative volumetric strain which provides a parameter that reflects whether the fracture network is dominantly opening or closing over the course of the injection program.
In this study, we examined microseismicty from three stages of a multistage hydraulic fracture treatment in a shale gas reservoir in North America. The SMTI analysis is performed and failure mechanisms are calculated for events over the course of three subsequent stages. From the failure mechanisms, the cumulative volumetric strain is calculated and plotted versus time over the duration of each of the stages. For each of the three stages, the cumulative volumetric strain is compared and the dominant fracture state (opening or closing) is determined. The results suggest that interconnectivity of the hydraulic fracture treatments is complex and can lead to increases or decreases in the effective fracture network.