bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimation Of Uncertainty In Microseismic Event Location Associated With Hydraulic Fracturing
Authors: Castano A. F. , Sondergeld C. H. , Rai C. S. 
Published: February 2011

Abstract
The efficiency of hydraulic fractures largely determines the economics of tight sands and gas shale reservoirs. Efficiency is defined by the fracture conductivity which results from the stimulation treatment. This is a function of fracture half length and height. Independent measures of fracture length and height, and containment provide prime data in evaluating stimulation treatments. Downhole or surface microseismic monitoring produce spatial distributions of microseismic events associated with hydraulic fracturing. These distributions provide the constraints on fracture length, height and containment. Most commercial product offerings ignore uncertainty in locations and biases produced by limited observation arrays. We examine these uncertainties and biases through an analysis of a simulation of event locations and sensor arrays. In addition, we investigate the errors produced by ignoring velocity anisotropy characteristic of gas shale.
We studied a set of synthetic microseisms locations. Simulations results demonstrate that mapping fracturing geometry with subsurface sensor arrays requires at least two observation wells (not a common field practice); this minimizes the geometry bias generated when only one observation well is used. One of the two observation wells should be aligned in the direction of the fracture azimuth. Failure to do so results in underestimation of the fracture half-length by approximately 10%. This requires knowledge of the prevailing in-situ stresses directions prior to stimulation. Downhole sensors should be located at the same depth of the fractured formation to avoid errors in fracture height estimation which can be as much as 50%. Velocity anisotropy has a minimal influence on uncertainty in event locations when subsurface sensor arrays are modeled with horizontal velocities. Surface sensor arrays can lead to underestimation of the fracture half-length in the order of 30% to 40% depending on the anisotropy effect whereas fracture height estimation error can be as much as 4%. Analysis of surface sensors arrays which avoid production shutdowns, reveals fracture half-lengths can be underestimated by about 17% to 31% depending on the velocity anisotropy. Uncertainty in event locations using only the vertical velocity in an anisotropic velocity field reduces with increasing depth as expected. Recent analysis of spatial distributions of microseismic activity for effective permeability and diffusion coefficients requires improved location accuracy and estimations of uncertainty.
Unconventional Well Profitability vs. Asset Profitability
Authors: Sedillos Lia , Roundtree Russell , Wright John , Miskimins Jennifer 
Published: February 2011

Abstract
The reserves growth in unconventional resources over the last three years has taken everyone by surprise and the ramifications are only now being fully realized by the marketplace and government. The role of shale basins in this growth has forever changed the skill expectations of oil industry professionals. This growth, primarily focused in North America today, will almost assuredly spread globally.
The economics of unconventional resource plays are quite different from those of conventional plays. Even the business metrics of success are usually ranked differently (Roundtree et al, 2009). This paper examines the overall cost structure of unconventional plays (land, drilling, completion, and well operation) versus the potential return. Prudent application of front end exploration to enter a play under favorable land price conditions, pragmatic well construction and completion practices to control costs, and efficient development drilling programs to optimize the resource recovery factors must all be considered in overall resource play economics. We demonstrate how irrational pursuit of lower development costs can often be detrimental to overall play economics and ultimate resource recovery.
Investor and governmental pressure may grow as these stakeholders segregate the operators who excel in achieving a balance of the different factors to sustainably produce better economic returns for their shareholders while extracting the maximum recoverable resource from the reservoirs in question. Stranded reserves will be seen ever more so as a measure of engineering malfeasance and not just sub-optimum economics.
Integrating Nuclear Magnetic Resonance, Production Logging, and Well DST Data: A Case Study in Carbonates From Brazil
Authors: Netto P. , Tinoco F. L. , Souza A. M. , Beer R. , Araujo M. 
Published: February 2011

Abstract
Modern logging tools, including Nuclear Magnetic Resonance (NMR), allow geoscientists to integrate data and use advanced petrophysics techniques. The NMR logs estimate permeability curves based on empirical equations and their response are sensitive to the permeability trends in rock layers of a heterogeneous reservoir. Therefore, it is possible to define flow units based on NMR flow capacity. This process can even be enhanced if there are Production Logging results available.
This paper presents a technique applicable to well test interpretation which consists in estimating the permeability of flow units through the integration of NMR, formation tests and production log data.
The properties of each flow unit such as thickness, average permeability and effective porosity are estimated from the NMR log. Using these data a multilayer flow model is built, in order to determine a multiplicative factor for the prior defined average permeability from each flow unit honoring the results of DST data. Several simulations are performed by changing the horizontal and vertical permeabilities and skin factor for each flow unit, to obtain compatible results with the well test.
This technique is applied in Brazilian carbonates. The cumulative NMR permeability curves shows good agreement with PLT data, which means that the NMR can be used as a predictive flow unit identifier when PLT data are not available.
In conclusion, the technique permits the interpreter to test various scenarios in a multilayer model, using different combinations of permeability and skin values for the flow units. This petrophysical model can also be used as an input for the dynamic simulation of the reservoir.
Solid-Particle Erosion in Slug Flow
Authors: Throneberry J. M. , Zhang Y. , McLaury B. S. , Shirazi S. A. , Rybicki E. F. 
Published: February 2011

Abstract
Sand erosion in multiphase flow is receiving widespread attention from the oil and gas industry. Several tools to predict erosion have been developed. One tool, called SPPS (Sand Production Pipe Saver), predicts penetration rates (pipe thickness loss rate) in fittings such as elbows. This tool accounts for many different operating conditions and can also be used to predict threshold flow rates that will result in only a tolerable amount of erosion. The SPPS model can be used to help avoid major pipeline failures, plan inspections and maintenance, develop cost to benefit projections, or estimate life expectancy of a pipeline for known flow conditions and sand production rates. Many flow regimes can occur in multiphase flow. This study focuses on the flow properties that effect sand erosion rates for slug flow. Experiments were conducted and a mechanistic flow model was developed. Erosion data were obtained for slug flow through an elbow and in a straight section of pipe. Erosion data show the effects of varying the superficial liquid and gas velocities, the liquid viscosity, the sand size, and sand rate. Data acquisition was accomplished through electrical resistance (ER) probes. Two flat-head ER probes were positioned in an elbow at 45° and 90° flush with the pipe wall. One intrusive probe was deployed in a straight section and protruded into the flow. Increasing the superficial gas velocity in these flow regimes extensively increases the erosion rate while increasing the superficial liquid velocity does not significantly increase erosion. Increased viscosity decreases the impacting velocity of impinging particles, and thereby reducing the magnitude of erosion on the pipe wall. The affect of particle size has been investigated and found to vary with viscosity. These trends were also found to vary with location of the probe. A mechanistic erosion model was also been developed. Model results are compared with sand erosion data. Predicted erosion rates from the model developed during this investigation agree well with the data collected in the present work and in previous studies.
Rethinking World Oil-Shale Resource Estimates
Authors: Biglarbigi Khosrow , Crawford Peter , Carolus Marshall , Dean Christopher 
Published: February 2011

Abstract
World oil shale resources are massive compared to conventional oil, making oil shale one of the world's largest known fossil fuel resources. The estimated oil shale resource in place for various countries is an evolving and growing number. The total world resource estimated by the USGS is currently 2.8 trillion barrels of shale oil; but may be as high as 8 trillion barrels depending on the quality of oil shale deposits considered.
In 2009, the USGS updated the resource base estimate for the U. S. Piceance Creek Basin, part of the Green River Formation, from 1.0 to 1.5 trillion barrels of oil shale. More than 1.8 trillion barrels of oil are believed to be trapped in shale in Federal lands in the western United States in the states of Colorado, Utah and Wyoming. This resource alone is over three times the proven reserves of Saudi Arabia. While the Green River Formation is the largest deposit of oil shale, there are over 30 countries with known oil shale deposits world wide.
With the price of oil staying well above $50 per barrel, new production technologies being considered by private companies for oil shale development may be economic. As these technologies are developed, resource estimates are also becoming more accurate. This paper describes some of recent resource estimates that have been further analyzed with measures such as resource yield and thickness also being described. Estimates will include the USGS update of the Green River Basin and results of Canadian exploration in the Albert Mines and in the Pasquia Hills. The paper will also provide an overview of global oil shale operations, including those in Estonia, China, and Brazil. Finally, this paper will provide a comparison of world oil shale resources and potential production profiles providing a world view of oil shale resources.
Shale Gas Well Completion Logistics
Authors: Tymko Dean W. 
Published: February 2011

Abstract
The introduction of large, multi-stage fracturing to the shale gas industry has made previous uneconomic shales economic to complete. These large scale stimulations present a new challenge in planning and logistics in order for the completion operation to be successful.
This paper provides an overview of the planning, execution, and improvement of logistics that went into the first two shale gas well completions in Northeast British Columbia, Canada for a large Canadian Energy Company. The logistical requirements taken into consideration when designing the first multi-stage horizontal well completion were: Fracture Stimulation, Lease, Fluid, Proppant, Equipment, and Completion Procedure. Planning these requirements started six months before completion operations commenced in order to meet the target pumping date of the stimulation and avoid costly delays.
The learning from the first shale gas well completion improved the logistics on the second shale gas well completion and the experience from the first two completion operations will shape future logistics as the project proceeds into the future. This paper shows that proper planning on large shale gas completions can pay off in well run, efficient completion operations that meet timing and cost objectives.
A Major Advancement in Expandable Connection Performance, Enabling Reliable Gastight Expandable Connections
Authors: DeLange Richard , Gandikota Raju , Osburn Scott 
Published: February 2011

Abstract
Since the introduction almost fifteen years ago of today's solid expandable liner systems, threaded connection technologies have advanced very little compared to the development of sophisticated, state-of-the-art expansion tools and systems. The severity of damage caused to threaded connections during the downhole expansion process leaves some threads unengaged and badly deformed reducing the connections’ mechanical dependability. Even worse, traditional metal seals incorporated into most proprietary premium connections are destroyed during the expansion process or damaged to the point of being undependable.
Even though solid expandable liner systems offer a large number of important and valuable solutions, connection performance is obviously a problem. For more than a decade, engineers have worked on the development of connection features that are more resistant to damage caused during expansion. Although there has been some advancement, today most or all expanded connections today share little resemblance to unexpanded connections when subjected to ISO 13679 qualification tests with gas.
This paper details new expansion cone technology that eliminates the majority of damage caused to connections when expanded with traditional cones. This paper will provide Finite Element Analyses and physical testing verification to show how this new technology leaves connections with minimal visible damage to the threads and metal seals after expansion.
High-Fluid-Loss, High-Strength Lost Circulation Treatments
Authors: Sanders Mark W. , Scorsone Jason T. , Friedheim James E. 
Published: February 2011

Abstract
A new high-fluid-loss, high-strength (HFHS) pill system has been developed and optimized using innovative test methods and trialed to ensure that it meets field criteria for addressing lost circulation problems. This new HFHS pill system works over a wide range of loss rates and provides a more effective and stronger seal than traditional treatments.
While the issue of lost circulation is one of the drilling industry’s most singular problems, the solutions are numerous and varied. Estimates of direct and associated costs to the lost circulation problem run into hundreds of millions of dollars globally, including whole mud losses, cost of treatment as well as lost time and tools. Discrete pills, formulated using a specific chemical and/or material blend, is one of the more popular approaches for curing severe lost circulation. These pills are mixed, pumped and spotted with the intention to either seal the loss zone or at least mitigate the losses sufficiently to regain the ability to circulate the wellbore fluid, control the well, and either continue drilling or set a string of casing.
Using new and innovative laboratory test methods, this paper evaluates the effectiveness of several commercially available defluidizing lost circulation treatments and discusses the development of a new HFHS lost circulation system. This new treatment has been designed and optimized using unique methodology to meet a set of “ideal” criteria for use in the field. Specifically, it must be easy to deploy, carry a low operational risk, as well as being effective at curing losses.
Fracture Network Development and Proppant Placement during Slickwater Fracturing Treatment of Barnett Shale Laterals
Authors: Xu Wenyue , Thiercelin Marc , Calvez Joel Le , Zhao Ruhao , Ganguly Utpal , Weng Xiaowei , Gu Hongren , Stokes Jerry , Moros Horacio 
Published: February 2011

Abstract
This paper presents an application of the wiremesh hydraulic fracturing model to analyze slickwater fracturing stimulation treatments of three Barnett Shale horizontal gas wells. For each treatment stage, the created hydraulic fracture network (HFN) was characterized on the basis of associated microseismic events distribution, treatment data, and geomechanical properties of involved formation layers. A systematic analysis of all stages, such as the potential effect of earlier treatment stages on a later one, the relationship between HFN properties such as the fracture surface area and treatment parameters, etc, was also presented. The information obtained was then applied to examine proppant placement in each of the HFNs. Potential ways of treatment improvement and optimization for future jobs are discussed based on these analyses.
Revolutionizing Offshore Production by InLine Separation Technology
Authors: Fantoft R. , Akdim R. , Mikkelsen R. , Abdalla T. , Westra R. , de Haas E. 
Published: February 2011

Abstract
The separation process is the heart of the offshore production system. Conventional technology requires massive equipment to allow for required separation of oil, gas, water and sand. Most separation equipment is based on gravity separation principles that require larger retention times and low fluid velocities. These separators have over several years been subject to further development by introduction of new separation principles. Advanced separator internals have been an important contributor in this respect.
During the last decade, Inline Separation Technology has successfully been introduced to several applications. Inline Separation is separation in pipe segments instead of within large vessels. Especially separation by use of cyclonic forces has been important. Inline technologies for separation of gas and liquid, oil and water as well as sand from liquid and multiphase streams have been developed and are already used extensively in retrofit applications to increase the performance and capacity of existing offshore production systems.
As the inline technology matures, total production systems can be developed based on use of inline separation technology. This will allow for substantially more compact and cost efficient field developments. It will also enable new applications, such as heavy oil and deepwater subsea applications, which are not feasible to develop with conventional technology.
This paper gives an overview of the inline separation technology and how this technology can be used to make improvements to offshore production system designs.
Landslide Hazard Assessment, Monitoring, and Stabilization: Villano Oil Pipeline System, Ecuador
Authors: Vasconez F. , Estrella M. , Velastegui A. , Nunez J. , Ponce H. , Riofrio P. 
Published: February 2011

Abstract
The Well sites of the "Villano" oil field are located on abundant biodiverse areas, part of the primary rain forest of the Upper Amazonas Basin. Due to its geological, geomorphological and climatic situation, the flowline that transports crude oil outside of this highly sensitive sector and the secondary pipeline that transports dehydrated oil to the Trans-Andean pipeline, are strongly susceptible to the affects of landslides, which can break the pipeline causing a serious environmental impact.
To assess the landslide hazards of the whole oil-pipeline route, the topographic basis maps were based on the aerial photographs utilizing aerial photogrammetric, restitution and rectification. Geological and landslide inventory maps were elaborated through photo-geology and fieldwork. For each identified landslide, the cinematic, intensity of the process and probability of occurrence was evaluated. These parameters were charted by degree of danger. All this information was integrated into a Geographic Information System (GIS). On the second phase, main active and potential landslide areas are being investigated in detail and are being monitored with inclinometers, stand piezometers, crackmeters and survey monitoring. They are numerically modeled and stabilized.
After more than ten years, since the operation began, there have been no pipeline ruptures. One of the case-examples is the landslide of kilometric point K-25 of the flowline, where a preventive action was taken to construct a variant of the oil-pipeline-route based on various analyses. It was also necessary to perform stabilization works on another unstable hillside within an ecological Reserve. A cable bridge was constructed to support a portion of the pipeline.
This methodology could be applied in other pipeline systems. Nevertheless, it is worth mentioning that timely identification of hillside instability is very important. For this reason, preventive maintenance of the right-of-way must be performed constantly.
Pore Scale Simulation of Flow in Porous Media Using Lattice-Boltzmann Computer Simulations
Authors: Boek Edo 
Published: February 2011

Abstract
We describe the ongoing development of lattice-Boltzmann (LB) computer simulation codes to study flow in porous media at the pore scale. LB simulations have evolved over the past decade and are now used as a tool to calculate both single- and multi-phase flow properties directly at the pore scale using X-ray Micro Tomography (XMT) pore space images. We will review the development of our codes to study flow in two-dimensional micro-models, viscous fingering, chemical reactions, hydrodynamic dispersion and non-Newtonian flow. In three dimensions, we have developed our codes to calculate the flow in XMT images of the pore space, for both single- and multi-phase flow, resulting in predictions of the permeability. Very recently, we have extended the multi-phase flow model to include surfactants for reduction of the interfacial tension and wettability alteration.
Shale Gas Production Decline Trend Comparison over Time and Basins
Authors: Baihly Jason , Altman Raphael , Malpani Raj , Luo Fang 
Published: February 2011

Abstract
Production from shale gas reservoirs has formed an increasingly large part of the U.S. natural gas mix in the last few years. More than half of the rigs in onshore U.S. will be drilling horizontal wells with a large majority in shale plays. (Baker Hughes, 2010) Within the last year, shale gas plays have dominated the onshore U.S. natural gas drilling activity, with this boom occurring during a time of economic uncertainty. However, skepticism has recently been placed on shale gas production decline trends from consultants and investment firms, where estimated ultimate recoveries (EURs) and the overall economic feasibility of shale gas plays have been brought into question.
EURs of shale gas wells have been forecast in a number of ways within the industry. Some entities have been calculating EURs based on initial production rates (IPs). Others are applying the decline trends established in one basin to a different, newer basin with less production history. In other cases, two different operators may use different trend types in wells that are in the same location.
This paper seeks to more accurately assess the decline trends and EURs of these shale plays, if the decline trends are improving, and what returns are required to make a well economically feasible. This study compares the production trends of horizontal wells in the Barnett Shale, Fayetteville Shale, Woodford Shale, Haynesville Shale, and Eagle Ford Shale plays, analyzing each over time to determine if there have been improvements in production. Where applicable we address the impact that technology has made in this enhanced production. Furthermore, the decline trends of horizontal shale to horizontal tight gas sandstone plays are examined to look for differences and shed some light on potential EURs.
The results of the analysis helped establish which decline trends could be used to determine the EUR of these horizontal shale wells, or if a better methodology may exist. A basic economic analysis to estimate breakeven gas price for a median (P50) horizontal well in each play was performed.