bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lessons Learned From an Eagle Ford Shale Completion Evaluation.
Authors: Centurion Sergio , Junca-Laplace Jean-Philippe , Cade Randall , Presley Greg 
Published: October 2014

Abstract
A multi-disciplinary study combining reservoir, completion and production information enables understanding of how to optimize completion strategies and enhance well productivity. This study focuses on the Eagle Ford shale formation in northern LaSalle County. A data-driven approach is followed by first identifying general trends in completion designs from around 50 horizontal wells.
The study aims to identify parameters that have the most influence on production in the Eagle Ford shale formation. Multivariate analysis was implemented to determine which completion parameters are the main production drivers. Special attention was given to dataset filtering and processing.
Comparing well productivity across an entire play like the Eagle Ford can be challenging because reservoir characteristics change and operators employ various field development and completion design strategies. The study minimizes variations in geology and completion schemes by focusing on a 6-mile diameter area. Variation in completion design is also minimized by only considering newly completed wells with similar hydraulic treatment designs.
In addition to production trends, the use of stress profiles, rock properties and microseismic clouds are investigated to constrain modeling of fracture length and height.
Fracturing Fluid Effects on Young's Modulus and Embedment in the Niobrara Formation
Authors: Corapcioglu H. , Miskimins J. L. , Prasad M. 
Published: October 2014

Abstract
Shale plays and the evolving technologies of horizontal drilling and hydraulic fracturing are driving the petroleum industry in many regions. Due to their low permeability, hydraulic fracturing is necessary for economic production in these shale systems. The success of these reservoirs is dependent on optimized hydraulic fracturing designs, and requires an understanding of the mechanical properties of these reservoirs.
One of these properties, Young's modulus, can weaken the formation if it is reduced. This weakening of the formation can, in turn, lead to; increased proppant embedment into the fracture face and a subsequent loss of conductivity. In low permeability shale reservoirs, the conductivity achieved through fracturing is just as critical as in other formations, thus making proppant embedment an issue that needs to be fully understood. This paper focused on how different fracturing fluids impacted the Young's modulus of the Niobrara shale, a major producing formation in the states of Colorado and Wyoming, and how this change affects proppant embedment and conductivity with certain proppants.
Nanoindentation technology was used to determine Young's modulus changes in Niobrara core samples after they were saturated for 30 days in certain fracturing fluids, and after they were heated under temperature (180°F) for five days. Treated samples were then subjected to high pressure (3030 psi) with selected proppants, simulating a fracture to test the proppant embedment profiles using scanning acoustic microscope (SAM) and profilometer measurements.
The experimental results showed that Young's modulus decreased with fluid exposure regardless of the fracturing fluid type and also increased (rebounded) after a certain saturation time. The magnitude of decrease in Young's modulus values was dependent on fluid type and saturation time. In one extreme case, (when KCl+friction reducer fluid was used as treatment fluid for 30 days) Young's modulus decreased by approximately 80%. The Young's modulus reduction is believed to be mainly caused by a weakening of the calcite minerals. Higher reductions experienced by KCl based fluids could be due to a detrimental chemical reaction between KCl and calcite minerals. Results also showed proppant embedment and crushing are inevitable under the tested circumstances and are dependent on distributed stress on the contact points as well as proppant type and fluid exposure.
Study on the Application of Wellhead Compression in Offshore Facilities
Authors: González Díez N. , Slot H. , Smeulers J. P. 
Published: October 2014

Abstract
As gas fields mature and their reservoir pressure declines, gas production rates are reduced. Addressing other associated issues with low reservoir pressures, such as liquid loading, eventually leads to higher operational costs. In order to facilitate the production of mature gas fields, a possible solution is installing compression. By introducing compression, the well-head pressure is reduced, thereby allowing larger gas flow rates. Wellhead compression (WHC) is the solution by which a compressor acts locally over one or a number of wells. In this way, the backpressure for a number of selected wells can be reduced. A case study for an offshore field in the North Sea is used to investigate the feasibility and the best possible arrangement of WHC in a satellite platform.
Three possible engineering solution layouts at the satellite platform have been identified, to be checked against three design cases. Each solution is assessed on the basis of power requirements and equipment needed. Potential reliability issues are addressed. Potential products available in the market that be used have been highlighted, especially on the compressor and driver side. Statistical figures about the reliability of compressors and drivers are distilled from an offshore Oil & Gas Reliability database.
It is concluded that WHC on a satellite offshore platform can be best addressed with a multiphase pump, provided that sufficient liquid is available or necessary engineering is interesting enough to be undertaken. If that is not the case, a solution with a vertical-separator/slug-catcher and an oil-flooded screw compressor is encouraged. The best available driver for this arrangement appears to be a gas engine on the basis of plot space and reported reliability figures.
The present work represents a first step towards the application of well-head compression at offshore facilities. In addition to the conclusions, potential pitfalls are identified. Several uncertainties are addressed that would require further research. First, reliability issues associated to possible emulsions occurring in a screw compressor when water and condensate and/or oil are put in contact; second, reliability statistics regarding gas engines and screw compressors are in contrast with O&G operators' experience.
Enhancements in Fraction Measurements and Flow Modeling for Multiphase Flowmeters
Authors: Chazal D. , Fiore M. , Jolivet G. , Lupeau A. , Toussaint C. , Fournier B. , Hollaender F. 
Published: October 2014

Abstract
Multiphase flowmeters (MPFMs) have been used since the early 1990's in the oil and gas industry and have gained acceptance in many environments. They have been considered the primary metering option for a wide range of applications - from heavy oil to wet gas. The combination of operational benefits, measurement robustness, demonstrable accuracy, and auditability has improved their status from new, unproven technology to that of the premium mainstream metering option.
With more than a decade of experience acquired using a combination venturi and gamma-ray multiphase flowmeters, further gains in measurement quality and operational robustness have been achieved. We will illustrate how enhancements in fraction measurements using multi-energy gamma ray attenuation and a more comprehensive analysis of the gamma-ray spectrum have been developed and implemented to provide better measurement accuracy and stability, leading to enhanced performances in multiphase flow measurements.
Another area of improvement that has been pursued is in the field of modeling of multiphase flows through a venturi. Historically, single-phase flow equations have been used, being adapted to multiphase flows by semi-empirical means to account for their complexity. While such models have proven robust for most standard applications, they can reach some limitations in particular conditions. We will present how a more dynamic model that considers the nature of the flow has led to improved accuracy of multiphase flow measurements.
We present the scientific basis for the new enhancements as well as illustrate the accuracy gains achieved based on hundreds of flow loop test points, ultimately leading to the quantification of the accuracy gains obtained through those technological improvements.
Formulation of Porous Medium Momentum Equations Using Variational Principles
Authors: Kubota Leonardo 
Published: October 2014

Abstract
This work shows that the powerful tools of Analytical Mechanics are suitable to describing the physics of single-phase fluid flow in porous media. We present a derivation of porous media momentum equations (also referred to as generalized Darcy's Law) using variational principles. More precisely, we shall rely on the Lagrangian formulation of Mechanics – an analytical approach - instead of the traditional, geometrical and vector-based Newtonian approach to derive the differential equations governing the dynamics of the fluid velocity in the porous medium. The problem of fluid flow in porous media provides an interesting setting where one can apply the most general form of Lagrange Equations – derived recently by Pesce (2003) - which is capable of treating particle systems whose mass depends explicitly on time, generalized coordinates and velocities. If such dependence is overlooked, then the derivation of generalized Darcy's Law via the classical form of Lagrange Equations will produce erroneous results.
Comparison of Methods for Stochastic Multiphase Flow Rate Estimation
Authors: Zangl Georg , Hermann Roland , Schweiger Christian 
Published: October 2014

Abstract
Even though flow rates of oil, gas and water are the most important parameters of any hydrocarbon exploitation project, only a minor number of wells are permanently connected to a multiphase flow meter (MFM). Production well testing through a test separator is by far the most common practice to measure flow rates. This method comes with the restriction that only one well at a time can be tested, leading to sparse measurements over the production history of a well.
In addition, operating conditions of the test separator can differ from flow line conditions and results in a discrepancy of flow line rates versus test rates. To account for this effect the well-test results have to be reconciled, usually backwards from the sales/export meter to each well.
More and more wells are equipped with SCADA systems, measuring wellhead parameters in real-time. Data driven technologies are able to learn the correlation between well test flow rates and wellhead measurements, so that they can calculate production rates at any time between well tests. Data driven methods are fast, so that they can be applied in real time and are therefore sometimes called virtual meters. They can overcome the difference of well test and flow line conditions and predict fairly accurate rates.
This paper compares a very simple regression method (MLR), a classification method (random forest) and a back-propagation neural network (ANN). All three methods are trained on real-time data from step rate well tests obtained from three wells. A blind test is performed on all three trained models to compare the predictability of each method.
As the calculation time of these data driven methods is very short, they have been embedded in a stochastic loop to account for the variation of the acquired real time parameters during the tests. A standard deviation is calculated from the stochastic simulation. The standard deviation is not only a good measure of the predicting capability of each method, but also embraces all operational variations of flow conditions during testing. This leads to a better estimation of the most likely flow rate at current conditions.
Advanced Petrophysical Surveillance Improves the Understanding of Well Behavior in Unconventional Reservoirs
Authors: Ansari Rafay , Yadav Himanshu , Thiruvenkatanathan Pradyumna , Zett Adrian , Spain David , Gysen Alain 
Published: October 2014

Abstract
Multi-stage hydraulic fracturing in horizontal wells is an essential stimulation technique to enhance production and economics in unconventional tight gas sands in North America. However, one of the challenges that still remains is to understand and quantify the efficiency of each perforation cluster in order to optimize completions. Operators have used various production logging technologies in an attempt to understand completion efficiency. Even then, these low rate horizontal wells with unstable flow conditions and fluid segregation provide a challenging environment for production logging, and even the use of different tools / software provides no definitive answer. Absence of direct comparison between logging tools renders it difficult to assess the suitability of a particular tool in a given downhole environment. A field trial was thus conducted to acquire and compare the log data using two very different instruments, an array based logging tool and a downhole distributed fiber optic (DFO) with distributed temperature and acoustic sensing (DTS / DAS) capability.
A multiple array tool, consisting of multiple spinner and resistance arrays, was deployed downhole via tractor into a well that had been on production for approximately three months. Multiple up/down passes were made at different speeds in both lateral and vertical sections to assist with spinner calibration. Following this, a retrievable DFO system (with both DTS/DAS) was run in the same wellbore and data was collected continuously for two days. A memory temperature tool was also added to the DFO toolstring to ensure post-acquisition temperature calibration and depth correction.
This paper highlights the advantages and disadvantages of both logging techniques and suggests ways to improve flow profiling in low rate horizontal wells. It also shows that overall comparison of the data from the two tools looks good, with some differences resulting from the different nature of these measurements. This paper further shows how other surveillance data including radioactive proppant and chemical tracers, open-hole logs, cement bond logs, and geomechanical data in these horizontal wells can be used to complement the production logging results and provide insights to optimize future completions.
Attenuation-Based Quantitative Cement Bond Index with LWD Sonic: A Novel Approach Applicable to all Casing and Cement Cases
Authors: Pistre V. , Kinoshita T. , Blyth M. , Saenz E. 
Published: October 2014

Abstract
In recent years, there has been a strong interest in evaluating casing to cement bond with an LWD sonic tool. In 2013, we presented an amplitude-based approach, similar to what is used with wireline tools with its potential and limitations. During this study, extensive modeling was conducted and verified with real data sets to show that the amplitude of the signal propagating inside the tool collar can sometimes become larger than the signal traveling along the casing, which limits the applicability of the first-arrival amplitude for bonding evaluation in thin casings and heavy cements.
From observations made during this investigation, it was noted that when the collar arrival was affecting the casing amplitude signal, the apparent attenuation rate obtained in these conditions anti-correlated with the attenuation measured by a wireline tool. This surprising observation triggered a review of the physics of sonic signal propagation in cased hole and the development of a new formulation of the bond index when an LWD tool is used for the measurement.
This new approach uses the attenuation of the casing and tool collar signal along an array of receivers from an LWD sonic tool, which extends the quantitative cement evaluation to the full range of bond index in all types of casing and cements if the ambient noise level permits. This new methodology uses the knowledge of the propagation inside the tool collar, which is well characterized for new LWD tools.
This different methodology does not require any tool calibration, mud attenuation compensation, or the presence of a free-pipe section for in-situ normalization of the measurements. It is therefore free of user interaction and can be implemented in the downhole tool processor for real-time answers while drilling the cement. This provides a very early knowledge of the casing-to-cement-bond integrity before drilling through the casing shoe, thereby reducing drilling risks. The approach was validated with real examples that showed how the new approach overcomes the limitations of the amplitude-based process formerly used.
A Methodology to Determine Economic Viability for Early Phase Projects in Under-appraised Fields with Ambiguous Data
Authors: Saeedi Alireza , Villela Felipe , Bungo Elise , Kaygorodtsev Evgeny , Zuluaga Elizabeth , Wang Ben 
Published: October 2014

Abstract
Long interpretation time after drilling appraisal wells results in evaluating uneconomic development options further than they should be considered. This study presents how a project team developed a structured approach to evaluation of the results of an appraisal well in order to minimize turnaround time in making decisions on economic viability of a project after completion of the appraisal well.
A project team was created to define the opportunity and evaluate the economic viability of the project. The team developed a structured approach to facilitate rapid evaluation of the appraisal well results against an established project economic viability framework. The developed methodology consists of entering a preliminary production forecast and facilities and drilling costs into an economic model. A varying EUR (Expected Ultimate Recovery) multiplier was then utilized to determine the minimum required EUR to make the project economic based on DPI (Discounted Profitability Index) threshold. Different development scenarios in terms of facilities design and recovery mechanism were evaluated in this study. Once the minimum required EUR was obtained from the economic model, the team calculated the minimum appraisal well OHIP (original Hydrocarbon In Place) volume needed for an economic opportunity assuming a drainage area based on regional benchmarking study. The analysis also included a procedure to adjust the calculations based on net pay thickness in the appraisal well location relative to average field net pay thickness. The values obtained from this exercise were then used as a signpost for the appraisal well and was checked against the data collected from the well. This allowed for a quick economic viability analysis of different development scenarios and identification of scenarios that needed to move to the next phase for more detailed analysis.
Matrix Permittivity Measurements for Rock Powders
Authors: Seleznev Nikita V. , Fellah Kamilla , Phillips John , Zulkipli Siti Najmi , Fournie Bastien 
Published: October 2014

Abstract
Formation water content is one of the key petrophysical quantities provided by dielectric logging. However, to determine water content from formation permittivity measurements the rock matrix permittivity must be known. Uncertainty in the rock matrix permittivity values translates into uncertainty in the water content estimate, which is especially important in low-porosity formations or complex lithologies. Matrix permittivity values are not well known for a number of minerals and can also vary for the same type of mineral in different formations. Thus, a laboratory methodology for the accurate determination of matrix permittivity at dielectric logging frequencies is required to facilitate accurate log interpretation.
Matrix permittivity values can be measured on solid plugs (Seleznev et al., 2011). However, the plug-based methodology can be challenging in very low-permeability or unconventional reservoirs because of difficulties with plug drying. In addition, it is not readily applicable to unconsolidated formations. Finally, it may be impossible to cut solid plugs due to limited availability of rock material. Matrix permittivity measurements made on rock powders are capable of addressing all of these issues.
We introduce a methodology for laboratory measurements of matrix permittivity on rock powders at 1 GHz. The methodology is based on conducting dielectric measurements on mixtures of rock powders and liquids with variable permittivities in a dielectric resonator. The permittivity of the rock matrix is inverted from a series of measurements obtained on pure liquids and powder-liquid mixtures. The methodology was benchmarked on a collection of samples representing common oilfield lithologies with matrix permittivity values between 4.6 and 8.6. The reference matrix permittivity values were first measured on solid plugs. Then the plugs were crushed into powders and the matrix permittivity values were determined on powders following the proposed methodology. The values obtained on powders matched the ones measured on solid plugs within 0.2 dielectric units resulting in accuracies better than 1% for the water-filled porosity and better than 1000 ppm for water salinity.
This new methodology was applied to a number of core samples from a carbonate reservoir, offshore Sarawak where dielectric logging had been performed along with conventional core analysis. The resulting measured matrix permittivity values were then used to interpret the dielectric log measurement. Results showed a better estimation of water filled porosity and of the textural MN parameter than would have resulted from using ‘chartbook’ values of matrix permittivity. A consistent and optimized interpretation was obtained in porosities ranging from 5% to more than 30%.
A New Approach to Modeling Production Decline in Unconventional Formations
Authors: Ogunyomi B. A. , Dong S. , La N. , Lake L. W. , Kabir C. S. 
Published: October 2014

Abstract
Most decline curve methods have two main limitations; the model parameters as a rule are not functions of reservoir parameters and may yield unrealistic (nonphysical) values of expected ultimate recovery (EUR) because boundary-dominated flow may not develop in unconventional reservoirs. Over the the past few years, several empirical models have emerged to address the second limitation, but they are challenged by the time to transition from infinite-acting flow period to the boundary-dominated flow. In this study, we performed statistical and model-based analysis of production data from hydraulically fractured horizontal oil wells and present a method to mitigate some of the limitations highlighted above.
The production data were carefully analyzed to identify the flow regimes and understand the overall decline behavior. Following this step, we performed model-based analysis using the parallel-flow model (sum of exponential terms), and the logistic-growth model. After the model-based analysis, the model parameters were analyzed statistically and cross plotted against available reservoir and well completion parameters. Based on the conclusion from the crossplots and statistical analysis, we used design of experiments (DoE) and numerical-reservoir simulations to develop functions that relate the model parameters and reservoir/well completion properties.
Results from this work indicate that the production characteristics from these wells are highly variable. In addition, the parallel-flow model indicates that there are at least two to three different time domains in the production behavior and that they are not the result of operational changes, such as well shut-in or operating pressure changes at the surface. All the models used in this study provide very good fits to the data and all provide realistic estimates of EUR. The cross-plots of model parameters and some reservoir/well completion properties indicate that there is some relationship between them, which we developed using DoE and flow simulations. We have also shown how these models can be applied to obtain realistic estimates of EUR from early-time production data in unconventional oil reservoirs.