bluuebunny/crossref_metadata_2025_split huggingface dataset:
Appraising Unconventional Play from Mini-Frac Test Analysis, Actual Field Case
Authors: Ibrahim M. , Pieprzica C. 
Published: September 2016

Abstract
Unconventional reservoirs are an increasingly important worldwide resource. These reservoirs, generally defined by permeability values lower than 0.1 millidarcy, present today's engineer with unique challenges. To date, there are no available methods for evaluation of unconventional wells with respect to estimated ultimate recoveries (EURs). As a result, the conventional approach has been used resulting in initial well reserve and performance predictions containing large amounts of uncertainty. Ultimately, capital efficiency will suffer through these misinterpretations. A better understanding of completion efficiencies and of a well's performance in these new unconventional frontiers is needed.
This paper will present an optimized EUR prediction procedure for the ultra-low permeability unconventional reservoir. The data from a standard mini-frac test will be analyzed and interpreted to produce the desired results. Illustrated within is the integration of geological data, Mini-Frac test (DFIT) analysis, and logging data to predict EUR's and future performance profiles. The DFIT analysis shows itself to be the most influential in this predictive workflow. One should note that the critical step in the process is proper identification of the reservoirs parameters: initial reservoir pressure, permeability, fracture half-length, and reservoir boundary
A reservoir model was built using the results of the proposed workflow. Through multiple simulations, the model produced well-performance curves and EUR values that were in agreement. This procedure generates more accurate and reliable curves than the conventional decline curve analysis approach and properly applied, will improve individual well performance predictions with additional benefits including optimization of future completion metrics and spacing decisions.
Radio Frequency Identification RFID-Enabled Circulation Sub Improves Hole Cleaning in High-Angle Wells
Authors: Goodwin Alex , Reitsma Rienk , Osei-Kuffour Jonathan 
Published: September 2016

Abstract
Well cleanup operations require high fluid-circulation rates for efficient cuttings transport and hole cleaning. Conventional circulation subs are deployed in drilling applications such as slim-diameter wells to deliver higher circulation rates and cuttings removal. But because these subs require multiple trips downhole for mechanical or hydraulic actuation, they add rig time and costs while drilling complex, high-angle wells. This paper reviews a radio frequency identification (RFID) circulation sub that facilitates hole cleaning via remote actuation.
The RFID circulation sub is actuated using commands communicated by RFID tags as they pass through the inside diameter (ID) of the tool string, which replaces conventional actuation methods such as ball drop or darts. This sub can be selectively actuated any number of times during the same trip downhole for enhanced operational flexibility. And because no ball seats are present, the sub maintains a full-bore ID that facilitates higher annular velocity and turbulent flow.
This paper also reviews a field application in which the RFID sub was deployed in a multi-assembly tool string to clean out a perforated 7-in. liner section and cased-hole section for a North Sea well. Once the well reached total depth, the sub was opened, closed and reopened a number of times, on command, to facilitate hole cleaning and increase fluid circulation rates to remove the wellbore debris. The RFID circulation sub helped deliver a cleaned and conditioned hole that was ready for stimulation. By completing the entire operation in a single trip, the operator saved 1.5 days of rig time.
A Novel Test Automation Solution to Improve Petroleum Engineering Software Reliability and Development Efficiency
Authors: Chen Zhongming , Chaudhary Saleem , Xie Liangjun , Sui Xiaojing 
Published: September 2016

Abstract
Engineering software programs play a critical role in helping engineers understand complex engineering challenges and in analyzing engineering data to aid management in making the right decisions. Currently, it is almost impossible to present a job design without the help of engineering software. In petroleum industry this situation is especially true in the areas of reservoir study, drilling, hydraulic fracturing, cementing, and sand control, where the software is an integrated collection of the right technologies and is the "medium" used to transfer technology to end users.
Unlike a physical product, which has a solid touch and feel, the architectural design and detailed development of engineering software often seem like a mystery to users, because of the numerous, hidden algorithms. Ensuring the correctness of all the implemented logic and producing reliable software has always been the focus of software engineering. Theoretically, any change made to the software has the potential to affect the entire application and may require a full retesting of the application's functionality before release to the user. It is impossible to retest all logical combinations and algorithms by using traditional testing methodologies. A new automated test solution has been developed to revolutionize the process of software development and testing to improve software reliability. The new test automation technique enables the developer to record and document all testing on individual algorithms as well as algorithm combinations during early development phases. Most importantly, testing can be automatically repeated at a later stage as needed. This activity includes unit testing, module testing, integration testing, and the final entire application testing. The precision range can also be set in the proposed methodology.
Automated testing and retesting significantly improves the reliability of the software as it is developed during its lifecycle. The proposed methodology was validated by successful application of the new solution in our software development projects.
Use of Transient Tests to Monitor Progress of Flooding in IOR / EOR Operations
Authors: Kamal Medhat , Tian Chuan , Suleen Suleen 
Published: September 2016

Abstract
Improved and enhanced oil recovery methods (IOR and EOR, respectively) are used to increase recovery from proven reserves mainly following waterflooding. Monitoring and managing the progress of flood in IOR /EOR operations is currently a challenge to the oil industry especially in situations with large well spacing and cost prohibitive measures like drilling observation wells (e.g., offshore and deep water applications). Falloff tests have been proven successful under waterflooding operations to determine the reservoir properties in various banks around the injection wells and the location of the flood fronts (Abbaszadeh and Kamal 1989, Yeh and Agarwal 1992, and Kamal 2009). In this paper we share new development that extends transient testing and analysis technology to IOR and EOR operations during polymer flooding. With the expanded use of Permanent Downhole Pressure Gauges (PDHG), the new developed technique can be used without additional operational cost or interruption of field operations.
In this paper, the effects of polymer are described by shear rate dependent viscosity (non-Newtonian flow). We developed an analytical solution of wellbore pressure by combining the non-Newtonian fluids and the multi-composite reservoir models. The solution dose not only address the polymer region where the fluids follow either the power-law (Ostwald 1929) or the Meter model (Meter and Bird 1964), but also the Newtonian flow in the oil region with varying oil and polymer saturations in both regions. The developed solution was validated by analyzing synthetic data generated using a commercial numerical reservoir simulator. The solution provides a deeper understanding about the physics behind the transient pressure behaviors during polymer flooding, and can be applied to guide a better implementation of well tests. Interpretation method for falloff tests using the new solution and the conventional Bourdet derivative and Horner plots is presented indicating that existing commercial well testing software are sufficient to analyze data with the recent development. The new solution allows us to obtain the reservoir properties such as fluid mobilities in various banks and the location of the flood front.
The developed solution was applied to field data. The pressure behavior expected from the new solution was observed in field data validating our developed technique and yielding the characterization of reservoir parameters in various banks.
The novelty of this method of characterizing the dynamic properties of the various banks during injection of non-Newtonian fluids and the location of the flood fronts is that an analytical solution of pressure transient behavior in two phase flow of non-Newtonian fluids and Newtonian fluids was developed, validated and used to analyze field data. This is the first analytical solution developed for this type of problem.
Experimental and Numerical Investigation on Stress Dependence of Sandstone Electrical Properties and Deviations from Archie's Law
Authors: Farid M. F. , Arns J.-Y. , Pinczewski W. V. , Arns C. H. 
Published: September 2016

Abstract
Resistivity Index (RI) of Fontainebleau and Bentheimer sandstones was investigated at ambient and reservoir pressures down to low water saturations using the porous plate method. The measurements compared with computations directly on high-resolution three-dimensional images of the pore space using Digital Rock Physics. The numerical computations are in reasonable agreement with the experimental measurements down to water saturations as low as Sw = 10 %. The RI measurements show that both sandstones display Archie behavior at elevated pressure. However, at ambient pressure the RI for Fontainebleau sandstone deviates from Archie behavior at low water saturations. The pore-space images suggest that the deviation from Archie behavior is due to the presence of conductive percolating grain contact regions. Bentheimer sandstone for which grain contacts do not percolate, displays Archie behaviour both at ambient and elevated pressures. The present study extends previous work on RI of clean sandstones using micro-CT based analysis to high confining pressures and shows that for such sandstones the RI at elevated pressure displays Archie behavior down to low water saturations.
Combining Soluble Particle Diverter with Specially Engineered Proppant to Enhance Fracture Complexity and Post-Fracture Conductivity
Authors: Gomaa Ahmed M. , Spurr Naima , Pirogov Alexander , McCartney Elizabeth 
Published: September 2016

Abstract
The objective of this study is to introduce a technique of far-field diversion using a mixture of soluble solid particles and an engineered proppant that can ensure that the temporarily bridged fractures re-open and remain propped for hydrocarbon flow after the soluble material has fully dissolved. Far-field diversion is required inside the fracture network to increase complexity by creating additional branch fractures through overcoming stresses holding the natural fractures closed. Usually, diverter particles temporarily bridge inside the fracture to create a low-permeability zone that increases the net pressure within the fracture and enables redirection of the next fluid stage to previously unstimulated intervals. However, if the diversion does not include proppant, the created fracture may close after particle dissolution.
Two tests were performed in this study: solid bridging test to describe the bridging capabilities of solid particulate diverters as a function of fracture width (0.04 to 0.08 in.); and conductivity reduction tests to determine the reduction in the flow rate due to the particle pack permeability. Two types of particle diverters (Diverter A and B) were tested. Diverter A is typically used for low- to medium-temperature applications (less than 225°F) and Diverter B for high-temperature applications (greater than 225°F). The two diverters have nearly the same particle size and distribution, the only difference being a difference in particle shape.
Modeling performed before the experimental work indicated that a proppant size of 50 mesh or higher minimized the far-field segregation between the proppant and 20 mesh soluble particles under all modeled conditions. Modeling also showed that reducing the proppant size to a larger mesh number improved proppant placement in the far-field area with good vertical coverage. Based on this information, the diverter particles for the tests were selected to be in the medium-size range (10 to 50 mesh) while the proppant particles were selected to be in the fine size range (70 to 140 mesh). At a low injection rate, slickwater fluid (2 cP) may not have adequate transport characteristics to place soluble diverter particles for far-field application. Modeling indicated that a carrier fluid with viscosity of 10 cP could carry the soluble diverter at least 130 ft from the wellbore.
Experimental data, using the CFD recommended sizes of proppant-diverter mixture, confirmed that a loading of 0.5 ppga of Diverter A was needed to bridge and plug the 0.04-in. slot width, while only 0.25 ppga of Diverter B was needed to plug the same width. The spherical shape of Diverter B helps to bridge inside that fracture more than the flake shape of Diverter A. Finally, both diverters significantly reduced the conductivity of the test slot discs.
Methodology and Array Technology for Finding and Describing Leaks in a Well
Authors: Hill Freeman , Bond Andy , Biery Michael , Jagannathan Srinivasan , Walters Darren , Lu Yinghui 
Published: September 2016

Abstract
This paper presents a new technology and methods that can detect leak locations in a well and illustrate the flow profile of the leak. A substantial amount of time and effort can be used toward repairing leaks in wells, and these methods and technology can reduce that time. The paper shows results and compares them to other techniques for a well that had been shut in as a result of a small leak.
The new approach is based on a hydrophone array technology, modeling, and practices that can identify the depth and radial locations of a leak. The array uses beamforming to triangulate on the location of the noise caused by flow in the leak. In addition, with the configuration of the well, this method can be extended to map out the flow patterns, producing an image of the leak. The procedural methodology for locating a leak, combined with a technical description of this new technology, is provided to enable results to be duplicated on other wells.
Standard well practices for locating leaks are discussed, along with the methodology behind leak detection and obtaining leak flowing profiles. A field case study is presented for an Alaskan well in which a small leak was observed between annuli A and B, interrupting the production of the well. The leak was evasive as a result of its size and location. A combination of field practices and the new technology produced the location and a flow profile illustration of the leak. Other small leaks were found within the well, including a leaking gas lift mandrel and a suspected tubing thread leak. Most significantly, the annular leak was found less than 50 ft below surface. Because of its location and proximity to the surface, surface interference hampered standard practices, which prevented the identification of the leak point in the well. However, by using field practices and the array technology, the leak was identified, and its flow profile from annulus A to annulus B was mapped out, accurately describing the leak and providing a full understanding of it. This is significant because it is helpful for choosing the most economical method for addressing the issue and returning to normal production.
The methodology and new hydrophone array technology for detecting leaks is a novel approach. The ability to identify and present a leak profile in a well is highly beneficial because it can reduce time and repair costs. This paper presents field practices that support its relevance.
Remote Detection and Flow rates Quantification of Methane Releases Using Infrared Camera Technology and 3D Reconstruction Algorithm
Authors: Watremez Xavier , Labat Nadège , Audouin Grégoire , Lejay Bertrand , Marcarian Xavier , Dubucq Dominique , Marblé André , Foucher Pierre-Yves , Poutier Laurent , Danno Ronan , Elie Damien , Chamberland Martin 
Published: September 2016

Abstract
Hydrocarbon leaks in oil and gas installations present Health, Safety and Environmental risks. History of crisis management in oil and gas upstream has shown the value of efficient and accurate tools for quantifying the gas-leak rate and determining the perimeter of the hazardous areas.
In this context, Total initiated a multi-year R&D collaborative project designed to develop remote sensing technologies and architectures for remote detection, identification, quantification and visualization of gas leaks in the event of a crisis.
Total, the ONERA – The French Aerospace Lab – and ADCIS have developed a set of algorithms and software to measure, compute and visualize a methane plume using infrared optical imagers. Results are obtained in 3D and in real time. The following steps are involved: (1) Spectral images in the Long-Wavelength InfraRed (LWIR) region are captured by three hyper-spectral cameras located around a methane release point; (2) Concentrations of methane are measured linearly in ppm.m by comparing spectral images of the scene in the presence of gas and reference images acquired before the release; (3) An algorithm, drawing on tomography techniques, computes concentrations of methane in ppm from the linear concentrations; (4) Mass balance type equations finally help estimate the methane flowrates based on the set of concentrations and local wind data information.
A one-week test campaign was organized in September 2015 and consisted of performing twenty-six methane gas releases of 1 g/s to 50 g/s. Three Telops Hyper-Cam cameras were connected as part of a network to a main server which ran the tomography and flowrate estimation code. The real-time remote detection and quantification worked fully.
During the campaign, good accuracy was obtained at the low flowrates of 1 g/s and 10 g/s of methane. At the higher flowrate of 50 g/s, quantifications were underestimated due to an oversaturation phenomenon. Further works, the aim of which is to adapt the instrument sensing ranges to the maximum concentrations encountered, should help improve the accuracy of these quantifications.
The innovation lies in the fact that a 3D visualization of the methane plume can be computed and created in real time and that flowrates and concentrations can be quantified, also in real time. This technology could be applied in environmental monitoring and crisis management.
Extreme Expansion Openhole Packer with HP/HT Capabilities
Authors: Mills Aubrey , Deng Guijun , Wakefield John , Prieto Carlos 
Published: September 2016

Abstract
The increasing demand for annular isolation in openhole applications drives the need for tools to operate in non-controlled bores where large washouts can limit the reliability of sealing in fracturing, off-bottom cementing and other operations performed in openhole. The service industry has been developing technology to meet these challenges for years but these efforts have often resulted in costly solutions and less than desirable pressure ratings or production rates.
A milestone was recently achieved in openhole packer development due to collective advancement in design process, state-of-the-art polymeric material development and design validation utilizing fiber-optic sensors. In-house testing indicates superior results: HP/HT capacities with the enhanced capability of operating in ~288% larger radial gaps, 50% lower setting pressures and 67% lower swab-off pressure. An important discovery from the use of fiber-optics was confirmation of the self-energizing nature of the packer along with data directly relating setting pressure to casing stress and thus the near wellbore. This technology and methodology will fundamentally change packer design and could be the greatest breakthrough in this area over the last 50 years.
This paper elaborates on how the design process is integrated with concept evaluation, material selection and qualification, design optimization using structural analysis techniques, rapid design experimentation and design validation utilizing fiber-optic sensors to achieve 13,000 psi [89,632 kPas] and 5,000 psi [34,474 kPas] ratings at 350 °F [450 K] for gauge and large washout geometries, respectively. This technology is currently being evaluated in field trials in the Middle East.
The Next Generation of E&P Development Programs: Flipped, Blended and Mentored
Authors: Donohue David A , Bulath Zsolt , Kavanaugh Kimberly , Donohue Tim , Ogle Kenneth 
Published: September 2016

Abstract
Development programs for the next generation of E&P specialists will be considerably different from those of the past. Enhanced learning methods, improved virtual communications systems, expanded online learning resources, the use of competency based job models to guide learning design, new learning approaches which rely more on mentors than lecturers, increasingly realistic simulation games and other methods will all contribute to achieving more effective and less costly learning outcomes. These drivers will be enabled by a Millennials culture that is highly attuned to the use of technology and impatient to achieve outcomes. In this paper, the authors summarize how these drivers contribute to the design of the next generation of learning programs, list the various resources and communications systems that exist or need to be developed and outlines some potential program designs. They conclude with a case study that demonstrates a "next generation program" that has been designed by the authors and is currently being implemented by a European oil and gas company for its specialists who work on several continents. The cost-effectiveness of such programs relative to traditional programs—particularly in a low oil price environment—will be welcomed by employers who are looking for real and substantial development outcomes for their new employees.