bluuebunny/crossref_metadata_2025_split huggingface dataset:
Global Unconventional Gas Resource Assessment
Authors: Dong Z.. , Holditch S.A.. A. , McVay D.A.. A. , Ayers W.B.. B. 
Published: June 2014

Summary
Most estimates of the resource endowment [original gas in place (OGIP)] reported for world unconventional gas start with Rogner's top-down study (Rogner 1997). That global estimate is most likely quite conservative because the oil and gas industry has discovered enormous volumes of shale gas around the world since the 1990s. The data from these new reservoirs add substantially to our understanding of the unconventional resource base. Furthermore, the uncertainty of Rogner's assessment was not quantified. Thus, considering the uncertainty, a new assessment of original unconventional gas in place worldwide is needed.
The objective of this project was to estimate the probabilistic distributions of original volumes of gas trapped in coalbed, tight-sand, and shale reservoirs worldwide. To accomplish this objective, we reviewed published assessments of coal and conventional and unconventional resources and established the quantitative relationship between unconventional gas [coalbed methane (CBM), tight-sands gas, and shale gas] and the conventional hydrocarbon (coal, conventional gas, and oil) resource endowments for North America. Then, we used this relationship to extrapolate original unconventional gas in place worldwide. Our assessment of the world resource endowment established an unconventional OGIP of 83,400 Tcf (P10) to 184,200 Tcf (P90), which is 2.6 to 5.7 times greater than Rogner's estimate of 32,600 Tcf.
Our regional assessments of unconventional OGIP should help industry better target its efforts to rapidly accelerate the development of unconventional gas resources worldwide. The methodology used to assess the distribution of each type of unconventional OGIP may be used to estimate unconventional gas resources at the country or basin level, given knowledge of the coal in place and technically recoverable resources of conventional hydrocarbons.
The ABCs of In-Situ-Combustion Simulations: From Laboratory Experiments to Field Scale
Authors: Gutiérrez Dubert , Moore R. Gordon , Ursenbach Matthew G. , Mehta Sudarshan A. 
Published: June 2014

Summary
Air-injection-based recovery processes are receiving increased interest because of their high recovery potentials and applicability to a wide range of reservoirs. However, most operators require a certain level of confidence in the potential recovery from these (or any) processes before committing resources, which can be achieved with the use of numerical reservoir simulation.
In a previous paper, (Gutiérrez et al. 2009) it was proposed that after successful laboratory testing, analytical calculations and semiquantitative simulation models would be used for pilot design and further optimization of the actual operation. However, the specific steps for building the field-scale-simulation models were not addressed explicitly. This paper discusses a detailed workflow that can be followed to engineer an air-injection project using thermal reservoir simulation.
The first step of the simulation study involves the selection of a kinetic model that either can be developed specifically for the reservoir in question or taken from public literature. Second, the oil would be characterized in terms of the same pseudocomponents employed by the kinetic model, and relevant pressure/volume/temperature (PVT) data would be matched to develop a fluid model for the thermal simulator. This new fluid model is used in the field-scale-simulation model to history match the production history (i.e., before air injection) of the field. Third, relevant combustion-tube tests would be history matched to validate the kinetic model and refine the thermal data that would be entered into the field-scale model. Finally, the results and knowledge gained from the combustion-tube match(es) are applied to the field-scale model with the proper upscaling of some parameters. This simulation model would aid in selecting optimum well locations and operating strategies of the pilot. It would then be refined as the actual operation progresses to enhance its predictability and allow further optimization of the project.
Technical considerations, advantages, and limitations of each step of the workflow are discussed in detail. This paper also presents workflow variations and recommendations applicable to new and already-mature air-injection projects for which simulation models are being developed.
Propagation of Nanocatalyst Particles Through Athabasca Sands
Authors: Zamani Amir , Maini Brij B. , Pereira Almao Pedro 
Published: June 2014

Summary
This paper presents results of an experimental study that systematically examined the propagation of nanodispersed catalyst suspension in sandpacks prepared with Athabasca reservoir sand and operated at the reservoir conditions. The concentration and size distribution of the particles at the injection and production end were measured. The pressure drops in different segments along length of the sandpack were monitored continuously. The retention behaviour of particles at the end of each experiment was examined by measuring the catalyst concentration in the bed as a function of the distance from the injection end of the sandpack and also by analysis of extracted samples using scanning electron microscopy. The results show that it is possible to propagate the nanodispersed catalyst suspension through sand beds without causing permeability damage, but a small fraction of the injected particles is retained in the sand. It was found that significantly higher retention occurs in the entrance region of the bed (compared with downstream regions) and that the total particle retention was higher in the Athabasca sand beds than in clean silica sand with the same flow and suspension properties. To the best of our knowledge, this is the first experimental study on transport of nanoparticles dispersed in viscous oil through reservoir sand beds. It provides valuable information on propagation and retention behaviour of nanoparticles. Considering the rapidly rising use of nanoparticles in industry, such transport will be encountered in numerous industrial applications and environmental problems.
Practical Control of SAGD Wells With Dual-Tubing Strings
Authors: Stone Terry W. , Brown George , Guyaguler Baris , Bailey William J. , Law David H.S. 
Published: June 2014

Summary
Practical methods of operating dual-/triple-tubing strings, on the basis of temperature monitoring that is currently available, to achieve uniform steam-chamber development and enhanced production in a steam-assisted-gravity-drainage (SAGD) process, are presented. The work is motivated by the fact that numerous operators use dual-tubing strings for designing and optimizing steam-chamber development. Flow in the region of the SAGD horizontal well pair is often irregular, and dual-tubing strings may help to even out and improve both injection and production. Problems that operators have with multiple tubing strings in wells include their control and design. In this work, the injector and the producer will have two tubing strings each: one landed at the toe and the other at the heel. Control points are applied on each injection tubular. Injection at these control points is regulated by a proportional- integral-derivative (PID) feedback controller monitoring temperature differences between injected and produced fluids. A brief examination and discussion of the performance of control points in the production tubulars are also included. The PID controller will attempt to accomplish two goals: (i) to achieve evenness in injection and production conformance along both wells and (ii) to enforce a specified temperature offset between the injector and producer in order to improve oil production and reduce steam production and injection. Sensitivity of the feedback controller will be examined for (a) heterogeneity where several synthetic permeability patterns will be tested to gauge the effectiveness of coping with reservoir complexity, (b) update frequency where a comparison will be made between instantaneous and periodic updating of the controller error terms, and (c) ability of the controller to cope with early temperature rises in produced fluids. Well monitoring is accomplished through the use of high-temperature fibre-optic temperature sensing that is currently available. Results and further discussion are offered on whether an additional tubular landed at the midpoint of both wells will benefit production from a heterogeneous reservoir.
Design of Caprock Integrity in Thermal Stimulation of Shallow Oil-Sands Reservoirs
Authors: Yuan Yanguang , Xu Bin , Palmgren Claes 
Published: June 2014

Summary
Stakeholders in in-situ oil-sands development take caprock-integrity issues seriously. The industry is faced with the challenge of determining an optimal operating pressure in the reservoir where, in general, the pressure should stay significantly low to ensure the caprock integrity while being significantly high for enhanced oil production and economics. This paper presents a comprehensive work program on the subject for a shallow oil-sands play. Caprock integrity considers the induced stress and deformation in a caprock during the thermal stimulation of an oil-sands reservoir. A minifrac-test program is undertaken to define the original in-situ stress state. Laboratory tests are carried out to measure the deformation and strength properties. Simulations are run to calculate the induced stresses and evaluate them against the mechanical strength. This paper describes some important quality-control issues for these activities. For the minifrac tests, multiple cycles and use of flowback are promoted for enhanced efficiency and accuracy. Laboratory tests are recommended on whole cores in a drained condition at a slow strain rate. Numerical simulations should use site-specific and laboratory-measured material properties. On the basis of the limited sensitivity analyses, the thermal expansion coefficient of the reservoir and Young's modulus of the caprock are found to significantly affect the caprock deformation and/or induced stresses.
Viscosity Prediction for Solvent-Diluted Live Bitumen and Heavy Oil at Temperatures Up to 175-deg-C
Authors: Motahhari Hamad , Schoeggl Florian , Satyro Marco , Yarranton Harvey 
Published: June 2014

Summary
Accurate predictions of heavy-oil and bitumen viscosity as a function oftemperature, pressure, and composition are required for the design of thermaland solvent-based recovery methods. In this case study, the applicability ofthe recently developed Expanded Fluid (EF) viscosity model is tested onmeasured viscosities of diluted dead and live heavy oil and bitumen attemperatures from 20 to 175°C and pressures up to 10 MPa. Density and viscositydata were collected for a condensate solvent, dead (gas-free) bitumen, and deadheavy oil from western Canada, and for the corresponding live oils and dilutedmixtures of the dead and live oils with condensate solvent. Solubility,density, and viscosity data for heavy oil saturated with carbon dioxide(CO2) were obtained from the literature. The model was fitted to thedata of the dead oils and the condensate with average relative deviations lessthan 11%. The viscosity of the live bitumen and heavy oil was then predicted towithin 21 and 31% of the measured value on the basis of measured and calculatedlive-oil densities, respectively. Diluting the live and dead bitumen with 3 to30 wt% condensate or carbon dioxide reduced the viscosity by one to threeorders of magnitude, and the viscosities were predicted with an averagerelative deviation less than 16 and 24% on the basis of measured and calculatedmixture densities, respectively.
Saudi Aramco Intelligent Field Data Exchange Experience Using PRODML: Case Study
Authors: Beshri Abbas , Nixon David , Nasser Nasser , Suhaibani Raed , Muhawes Hamad 
Published: June 2014

Abstract
The rapid evolution of technological advancements in Intelligent Field equipment, real time monitoring & optimization over the past few years has contributed significantly to increasing production potential, recovery factor, and efficiency with the safest and environmentally sound practices. To achieve optimum results of the Intelligent Fields program, a reliable information infrastructure and architecture must exist.
Successful Intelligent Field implementation is based on two major components. The first one is a robust data acquisition and delivery infrastructure which is the backbone component of Saudi Aramco's Intelligent Field Surveillance Layer. Saudi Aramco has developed and implemented a set of standards, specifications, and guidelines to address and meet intelligent field requirements in terms of data types, frequency, resolution, security, integrity, quality, and reliability.
The other major and equally important component is the data processing and exchange workflows. This component plays an important role in achieving the other Saudi Aramco's Intelligent Field layers which are Integration, Optimization, and Innovation. Standardization of hydrocarbon production's data exchange between heterogeneous applications will considerably help to accomplish the overall objectives of the Intelligent Field Project.
Saudi Aramco's strategic aim is to implement a comprehensive E&P standards-based information architecture. The previous successful adoption of WITSML (Wellsite Information Transfer Standard Markup Language) enabled Saudi Aramco to standardize the drilling and completion information architecture. It allowed Saudi Aramco to leverage their investment in instrumention to enable new capabilities for automation and optimization that would otherwise be impossible or difficult to achieve. Also, it reduces the cost of information exchange between software and replacing or substituting software to benefit from improved functionality.
This paper will highlight Saudi Aramco's experience and methodology of assessing PRODML (Production Markup Language) functionality and usability in a pilot project. It will highlight examples, challenges, benefits, and limitations of the production standard PRODML.
Is Formation Damage an Issue in Shale Gas Development?
Authors: Wang Q. , Guo B. , Gao D. 
Published: June 2014

Abstract
Large scale hydraulic fracturing operations are often required for enhancing productivity of wells in shale gas formations. Due to the shally characteristics of the formation rock, the productivity of the hydraulically fractured gas wells seems to be very vulnerable to the damage by the fracturing fluids. The damaging mechanisms are believed to include fluid invasion, proppant embedment, gel filter cake at the fracture face, and the gel residue in the proppant pack. The relative significance of the formation damage due to each of the mechanisms is not clear. This paper presents result of investigations based on a new analytical model.
A new analytical well productivity model was developed in this study, considering the matrix cross-flow to long fractures and non-linear influx to short fractures. A new model involves parameters that describe the effects of fracture fluid filtration, proppant embedment, gel filter cake at the fracture face, and the gel residue in the proppant pack on the productivity of fractured gas wells in shale gas formations. Sensitivity analyses with the model show that, fracturing fluid invasion, proppant-embedment layer, gel filter cake residue at the fracture face, and gel residue inside the fracture may reduce well productivity by upto 12.5%, 0.6%, 6%, and 7%, respectively. The significance of the damage to well productivity should not affect gas production rate in a way that would be noticed.
Chevron's Digital Oilfields Solutions and Base Business Processes Maximize Value at McElroy Field, West Texas
Authors: Taylor William C 
Published: June 2014

Abstract
Chevron's digital energy program, i-field, began in 2002. Its focus is to enable integration of asset activities, relevant-time data, analysis and decision-making, and the design of purpose-built workflows to implement new i-field solutions.
The McElroy Field is a large waterflood located in the Permian Basin. Waterflood management at the McElroy is challenging due to reservoir complexity combined with drilling activity, well work, well count, varying artificial lift systems, high fluid volumes, and multiple injection systems. To efficiently manage the field, the technical team embraced i-field solutions and Chevron Base Business processes. The result is an efficient operation which is managed by exception using real time data.
The McElroy Team worked with Chevron's i-field team to map waterflood management workflows. The workflow designs reflected decisions being made, data requirements, data sources, and data quality. Subsequently, tools were developed that could access the data, apply filters, and present the results for review. To enhance the usage of the integration tools, an Asset Decision Environment (ADE) was built, enabling faster and more informed decision-making. The McElroy team also implemented Chevron's Integrated Production System Optimization process. A tool was built to capture facility information and the theoretical capacity. Forecasted production volumes were checked against equipment capacity to identify bottlenecks.
Application of i-field tools and the IPSO process have significantly impacted McElroy. The number of injectors within 10% of their target rate increased from 185 to 275 wells within 8 weeks of IMET implementation. The number of prospective workovers increased to over 100 wells once a well surveillance tool was incorporated into daily workflows. There has been a flattening of production decline directly related to improved injection and production well management made possible through the use of digital i-field tools and solutions.
A Two-Level Strategy to Realize Life-Cycle Production Optimization in an Operational Setting
Authors: van Essen G. M. , Van den Hof P. M. , Jansen J. D. 
Published: June 2014

Abstract
We present a two-level strategy to improve robustness against uncertainty and model errors in life-cycle flooding optimization. At the upper level, a physics-based large-scale reservoir model is used to determine optimal life-cycle injection and production profiles. At the lower level these profiles are considered as set points (reference values) for a tracking control algorithm, also known as a model predictive controller (MPC), to optimize the production variables over a short moving horizon based on a simple data-driven model. We used a conventional reservoir simulator with gradient-based optimization functionality to perform the life-cycle optimization. Next, we applied this optimal strategy to a set of reservoir models with markedly different geological characteristics. We compared the performance (oil recovery) of these models when applying the life-cycle strategy with and without the corrections provided by the data-driven algorithm and the tracking controller. In this theoretical study we observed that the use of the lower-level controller enabled successful tracking of the reference values provided by the upper-level optimizer. In our example, a performance drop of 6.4 % in net present value, caused by differences between the reservoir model used for life-cycle optimization and the (synthetic) true reservoir, was successfully reduced to only 0.5% when applying the two-level strategy. Several studies have demonstrated that model-based life-cycle production optimization has a large scope to improve long-term economic performance of water flooding projects. However, because of uncertainties in geology, economics and operational decisions, such life-cycle strategies cannot simply be applied in reality. Our two-level approach offers a solution to realize the theoretical potential of life-cycle optimization in a more operational setting.
Automation in Wellbore Stability Workflows
Authors: Wessling Stefan , Bartetzko Anne , Pei Jianyong , Dahl Thomas 
Published: June 2014

Abstract
Wellbore instability accounts for a significant amount of nonproductive time. Continuous improvement of today's technologies enables real-time analysis of acquired data to identify and remediate potential drilling hazards. Efforts toward the automation of relevant steps and processes for real-time wellbore stability modeling, monitoring, and calibration are considered highly important. Automation adds expertise to the rigsite engineers and enables simultaneous supervision of more than one well for remote operating engineers.
The complexity of the data flow, the reliability of the models, and the personnel required for monitoring pose great challenges for automation. Take pore pressure analysis as an example; some methods often require manual input from the user for placing normal compaction trend lines. Data used for pore pressure calibration (e.g., gas data) are more qualitative indicators rather than precise quantities. Important data are obtained only at discrete locations, such as leak-off tests for fracture gradient estimation. These examples illustrate the diversity of relevant data and information, which have to be properly managed.
In this paper we present some examples of the automation of single modules of a geomechanical analysis workflow. These include automatic setting of a normal compaction trend line and determination of the onset of overpressure using statistical methods, image interpretation algorithms to identify depth and width of breakouts, and automatic shale discrimination at the bit with drilling vibrations. These modules eventually become the building blocks of a complete automation system for wellbore stability.
Nikaitchuq ERD: Designing for Success on the North Slope of Alaska
Authors: Abahusayn Mishal , Foster Brandon , Brink Jason , Kuck Marc , Longo Joseph 
Published: June 2014

Abstract
A 52 well heavy oil field development targeting shallow (3,400-4,000 ft TVD) sands on the north slope of Alaska was initiated in 2008. Horizontal wells of 11,000 to 13,000 ft MD were drilled early in the program. These initial wells served as "data-gathering and technology-proving" opportunities leading up to the eventual 23,000 ft MD wells. Key technical challenges include equivalent circulating density (ECD) and drag management.
ECD management became essential in the 8½" production hole section of the longer wells. A relatively narrow (&lt;600 psi) mud weight window necessitated changes to casing, drill-string, drilling fluids, and operational parameters. Lighter weight production casing allowed drilling a larger production hole (8¾" vs. 8½"). A tapered drill-string, reduced mud rheology, and reduced flow rate all became a necessary part of the ECD management solution.
Advanced drag management techniques are required to install the 9⅝" production casing, 5½" production liner, and 4½"x3½" intelligent inner-string completion. The 9⅝" casing is installed using the "buoyancy assist" method (ie, "floatation") so it may be "pushed" and reamed in the hole beyond the point of negative weight. The lower completion consists of a 5½" slotted liner with swell packers. Centralizers on the liner were changed from non-rotating to fixed, which allowed breaking axial drag while reaming the liners to depth.
Extensive torque and drag modeling was used to plan intelligent inner-string completions on the injector wells, which included injection control devices, swell packers, and a fiberoptic distributed temperature sensor (DTS) to monitor injectivity.
The full length paper will discuss the technical challenges, well design solutions, and operational practices that were trialed and implemented to enable extended reach wells to be successfully drilled on the edge of the industry experience envelope with all wells meeting targeted objectives.