bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unlimited Multistage Frac Completion System: A Revolutionary Ball-Activated System with Single Size Balls
Authors: Yuan Feng , Blanton Eric , Convey Brent , Palmer Chris 
Published: June 2014

Abstract
In recent years, there has been tremendous growth in multistage fracturing for unconventional plays employing multistage fracturing completion systems with openhole (OH) packers or cementing to isolate multiple stages and ball-activated frac sleeves with graduated seats (traditional graduated-seat frac sleeves) to divert the fracturing treatments. This phenomenon has developed primarily because these systems not only maximize production, but also save significant completion time and money with the ability to perform multiple stimulations in a single trip, with minimal or no thru-tubing intervention.
However, traditional ball-activated frac sleeves have graduated ball seat sizes for each additional zone, and therefore, each ball seat creates its own backpressure within the system. With the number of frac stages increasing, the ball seat sizes become smaller, leading to an increase in the surface pressure and hydraulic horsepower (HHP) required to generate a given net downhole pressure or flow rate. In order to solve these limitations, a revolutionary ball-activated fracturing system has been developed, which can be installed with an unlimited number of zones using a single size ball and ball seat for each zone. This new technology can greatly reduce frictional forces and enables a more efficient fracturing of each zone within the wellbore. Most importantly, this new frac sleeve is sized to achieve an inside diameter (ID) as close as possible to the host tubular string, thus requiring a much lower fracturing pressure on the surface compared with traditional graduated-seat frac sleeve.
This paper will present the operational mechanisms of this new frac sleeve, simulation of frac efficiency and financial analysis with quantitative comparisons between it and traditional graduated-seat frac sleeve. The analysis will indicate that this new frac sleeve technology can be used to optimize hydraulic fracturing operations in both HHP requirements and stimulated reservoir volume (SRV) while dramatically reducing operational time and overall completion costs.
Optimum Decision-Making in Reservoir Managment Using Reduced-Order Models
Authors: Alghareeb Zeid M. , Williams John R. 
Published: June 2014

Abstract
Reduced-order models (ROM) are considered powerful techniques to address computational challenges associated with reser-voir management decision-making. In this sense, they represent perfect alternatives that trade off accuracy for speed in a controllable manner. In this paper, we describe a model-order reduction technique that entails the use of proper orthogonal decomposition (POD), truncated balanced realization (TBR) and discrete empirical interpolation (DEIM) to accurately re-produce the full-order model (FOM) input/output behavior. POD allows for a concise representation of the FOM in terms of relatively small variables while TBR improves the overall stability and accuracy. DEIM improves the shortcomings of POD and TBR in the case of nonlinear PDEs, i.e.; saturation equation, by retaining nonlinearities at lower dimensional space. In this work, the use of ROM reduced the computational time by O(100) while providing good overall agreement with FOM. The use of large reservoir simulation models is expected to add additional speedup factors.
ROMs are potentially perfect alternatives to FOMs in reservoir management intensive studies such as production optimization. However, ROMs presented in this paper and the overall physics-based ROMs have the tendency to perform well within a restricted zone. This zone is generally dictated by the training simulations used to build the ROM. Therefore, special care is considered when implementing these training runs. To mitigate the heuristic process of implementing the training runs, we apply a ROM based trust-region method that provides an adaptive framework to systemically retrain ROM during the optimization run.
The ROM approach with trust-region methodology is applied to a heterogeneous model containing 13,200 grid blocks and five wells. The accuracy of the ROM is first demonstrated for several testing simulations in which the injection and production rates for each well differ from those used to build the ROM. A waterflood optimization case is then considered to determine the optimum injection and production rates for four producers and one injector at five different times (total of 25 control variables). Results for optimized net present value using ROM based trust-region is shown to be very close to those achieved using the full order model with a difference of only 0.2%. The runtime speedup factor for this case was about 31. The ROM approach thus appears to be well suited for use in applications in which many simulations must be performed such as production optimization and uncertainty assessment.
Fracture Characterization in Unconventional Reservoirs using Active and Passive Seismic Data with Uncertainty Analysis through Geostatistical Simulation
Authors: Maity D. , Aminzadeh F. 
Published: June 2014

Abstract
This study discusses a new workflow for fracture characterization and modeling using geophysical (microseismic and 3D surface seismic) data along with independent reservoir information (such as well logs). The framework is ideally suited for unconventional environments such as shale and tight reservoirs where modern technologies such as the use of hydraulic fracturing and passive seismic monitoring allow application of the proposed workflow.
The workflow involves generating geomechanical property estimates (including stress and weakness estimates) as derived from passive seismic data analysis and relevant seismic attributes derived from 3D seismic data combined using ANN based reservoir property modeling framework. The training information for the networks is generated based on a-priori information through image logs. Resolution of passive seismic derived velocity models is improved by using sequential Gaussian co-simulation by combining low resolution velocity maps high resolution seismic impedance data for phase velocity estimation. Uncertainty estimates are quantified by adequate number of realizations and associated probability density functions for fracture properties within study volume.
In this paper, different properties estimated through ANN modeling have been shared. New fracture identifier (FZI) properties have been defined and the models have been used to characterize fracture zones and major discontinuities for a representative unconventional reservoir (geothermal setting) used in our study. We also share uncertainty estimates for the identified fracture zones for improved characterization. Finally fracture property estimates for the study area (derived using FZI and other properties) have been generated for future reservoir simulation studies.
The proposed method allows for improved understanding of shale and other unconventional reservoirs through fracture mapping and provides a workflow for improved volumetrics of the reservoir by making use of identified properties for fracture modeling. This work validates the potential for using relatively low resolution passive seismic data for improved reservoir characterization using Geostatistical tools. It also provides a valuable framework for pseudo 4D characterization where a single 3D seismic survey can be used as the basis to characterize the reservoir in a time lapse fashion using new information collected in time through passive seismic arrays as well as new well logs being obtained within the area of interest.
Value of Competency and Value of Competency Assessment
Authors: Nieman Timothy L. , Schuyler John , Brett J. Ford 
Published: June 2014

Abstract
What is the value of a competent engineer? How can we be sure that an engineer is actually qualified? As the big crew change progresses, and as regulators worldwide are beginning to require operators to assure the competency of people working in petroleum operations, these questions are becoming increasingly important. This paper presents an approach to address these questions by looking at competency assurance with probabilistic models.
The value of a competency assessment is demonstrated with a decision tree value of information (VOI) analysis and shows that competency assessments are likely under-utilized. In addition to reducing the chance and impact of defective engineering, assessments provide important feedback to the engineer as learner.
A more detailed model uses Monte Carlo simulation for the stochastic (i.e., probabilistic) calculations, to model training, the design process, and multiple review stages during drilling, completion and production operations. The model uses a competency scale and shows the value of incremental competency improvements. With our judgments the calculations show a dramatic underuse of competency assessment. We further demonstrate how a personal learning initiative can measurably increase competency, and how that competency improves a typical project's value.
The simulation model can help management optimize decisions involving staffing, type and days of structured training, work process design, and design review stages. Added benefits of the modeling approach include tools for individual development, career planning, and organizational learning. We also relate competency and competency assessments to risk management, construction, and safe operations.
Modeling Microseismic Hydraulic Fracture Deformation
Authors: Maxwell S. C , Weng X. , Kresse O. , Rutledge J. 
Published: June 2014

Abstract
Microseismic evidence of fracture complexity has lead to the recent development of new modeling tools to simulate the growth of complex fracture networks. Typically these complex fracture models rely on calibration from microseismic location information, although microseismic source mechanics can also provide additional model verification. Modeled geomechanical deformation associated with hydraulic fracture stimulation of a complex hydraulic fracture provides information that can be compared with observed microseismic deformation. Partitioning of modeled strains into shear and dilatational components allows relative comparison of the appropriate displacement mode with observed cumulative microseismic moments. A number of simple fracture geometries are investigated to illustrate the deformation modes of the modeled fracture displacements. A workflow is also described where the input parameters of the simulation are varied to match both the footprint and deformation of the microseismicity, which then results in an estimate of the complete fracture network volume and proppant placement. In this way the effective stimulated volume can be assessed and used as input to a reservoir simulation to investigate well performance and reservoir drainage.
Assessing the Accuracy of a Production Forecast: West Africa Field Case History
Authors: Apanel Anna , Tester Robert , Thomson Brodie , Mateus Ginga , Marques Gaspar 
Published: June 2014

Abstract
The subject field is located in the deep water off West Africa. Over its 7-year life, the field reached a peak production of 90 thousand BOPD and produced nearly 100 million barrels of oil from a high-quality stacked Lower Miocene deep-water channel complex. This field provides a unique opportunity to perform a look back on how well the reservoir performance predictions made at project funding matched with the final actual field performance.
The West Africa field was a subsea development tied back to a FPSO (Floating Production Storage and Offloading vessel). The production forecast used for project funding was generated using a full field simulation model and optimized depletion plan. The original depletion plan called for crestal gas storage and peripheral water flood. Model properties were derived from a single exploration well and high resolution 3D seismic data.
The production forecast developed at project funding did a very accurate job of predicting average reservoir behavior such as most-likely ultimate recovery and production plateau. However, a more detailed comparison of the pre-production depletion plan and the actual field performance shows significant differences. In particular, both gas and water breakthrough and build up were faster than expected. These factors were offset by higher well productivity and larger in place oil volumes. 4D seismic acquired after 3 years of production was particularly effective in illuminating gas and water flow pathways in the reservoir that had not been modeled or predicted. In addition, changes were made to the original depletion plan to increase recovery and in reaction to operational issues. The factors that drove the evolution in the depletion plan are reviewed and an assessment is made on the accuracy of the original production forecast.
SPE is sponsoring a series of Global Integrated workshops on production forecasting with the objective of assembling guidelines. This paper presents the results of a comparison of a field's production forecast from project inception to abandonment. This example demonstrates that the assessment needs to involve much more than the numerical comparison of predicted volumes versus actual. During the course of field operation, enhancements are constantly identified to increase field recovery as our understanding of the reservoir improves.
Analytical Solutions for Gas Displacements With Bifurcating Phase Behavior
Authors: Khorsandi Saeid , Ahmadi Kaveh , Johns Russell T. 
Published: June 2014

SummaryMinimum miscibility pressure (MMP) is one of the most important parameters in the design of a successful gasflooding process. The most-reliable methods to calculate the MMP are based on slimtube experiments, 1D slimtube simulations, mixing-cell calculations, and the analytical methods known as the method of characteristics (MOC). The calculation of MMP by use of MOC is the fastest method because it relies solely on finding the key tie lines in the displacement path. The MOC method for MMP estimation in its current form assumes that the composition path is a series of shocks from one key tie line to the next. For some oils, however, these key tie lines do not control miscibility, and the MMP calculated by use of the key-tie line approach can be significantly in error. The error can be as high as 5,000 psia for heavier oils or CO2 displacements at low temperature in which three-phase hydrocarbon regions can exist (L1–L2–V). At higher pressures, the two- or three-phase region can split (or bifurcate) into two separate two-phase regions (L1–L2 and L1–V regions). Thus, for the MMP calculation from MOC to be correct, we must calculate the entire composition path for this complex phase behavior, instead of relying on the shock assumption from one key tie line to the next.In this paper, the MOC-composition route is developed completely for the bifurcating phase-behavior displacement for pure CO2 injection by use of a simplified pseudoternary system that is analogous to the complex phase behavior observed for several real displacements with CO2. We develop the MOC analytical solutions by honoring all constraints required for a unique solution—velocity, mass balance, entropy, and solution continuity. The results show that a combination of shocks and rarefaction waves exists along the nontie-line path, unlike previous MOC solutions reported to date. We show that by considering the entire composition path, not just the key tie lines, the calculated MMP agrees with the mixing-cell method. We also show that, in this complex ternary displacement, the displacement mechanism has features of a both condensing and vaporizing (C/V) drive, which was thought to be possible only for gasfloods with four or more components. For pure CO2 injection, the solution also becomes discontinuous for oils that lie on the tie line envelope curve. Finally, we show that shock paths within the two-phase region are generally curved in composition space and that there is no MMP for some oil compositions considered in the displacements by CO2. Recovery can be large even though the MMP is not reached.
Tight Hole Spotting in 3D Virtual Drilling Simulator
Authors: Mirhaj S. A. , Oteri V. A. , Sælevik G. 
Published: June 2014

Abstract
It is very important to understand the mechanisms involved during the tripping job and to know about the factors that come into play during and after the tripping operation. There are a number of downhole parameters involved that can interrupt the normal tripping activity and can lead to serious well control situations, such as blow out.
According to estimates in Louisiana, Texas during 1960- 1996, a total of 430 blowouts occurred during drilling, of which pulling out of the hole (swabbing) took the lead with 158 blowouts.
In addition to surge and swab that might come into play, one of the unforeseen problems in tripping job is tight hole that in worse case can lead to stuck pipe and brings about major Non-Productive Time (NPT) of the operation. The causes of tight holes include: Formation related problems (tectonics, etc), borehole trajectory, insufficient inhibition, improper mud weight, lack of lubricity and inadequate hole cleaning.
There are several problems that arise during tripping in/out in the wellbore but emphasis has been placed on tight hole in this study because of high financial impact the drilling industry encounters and downtime it poses during drilling operations.
In this study this challenge that is associated with tripping operations (tight hole) will be implemented in a 3D Virtual Drilling Simulator for a field case in the North Sea and interesting results have been presented. In addition to invaluable results inferred, the 3D Virtual Drilling Simulator can be used to train a complete drilling crew for a specific operation (i.e. RIH & POOH and related challenges).
Geomechanical Analysis to Develop an Extra Heavy Oil Offshore Field
Authors: Gavito Daniel García , Galicia Luis Ángel , García Juan Carlos , Cabrera Ana Corina , Duarte Anna Paula 
Published: June 2014

Abstract
Recent advances in petroleum geomechanics numerical simulations have encouraged industry to invest in finite element simulations to optimize drilling operations. One important part of the drilling process is to understand the rock mechanics behavior, such as deformation and strength through a stress-strain behavior. This work presents the case of study of an exploratory field located at the south of the Gulf of Mexico. This field has two offset wells already characterized by a post mortem 1D MEM (Mechanical Earth Model) study, faults and horizons already interpreted in depth. The principal objective of this study was to develop a consistent in-situ stress state of this field through an in-house finite element program with the help of geoscience analysis & data generation software. The final product of this work will help deliver a consistent stress analysis for the drilling of a planned well in the same field. The rock formation was modeled through a non-linear model. A Mohr-Coulomb with unconfined compressive strength input was used to simulate the formation. The finite element mesh representing the field was fed with elastic and geomechanical properties from the geoscience software, allowing the discretization of the different formations and faults also. Initially this mesh had a size of 74*74*42 and then it was embedded (104*104*62) to let far field stresses act on it. After many simulations the stresses obtained from the simulation were validated against the two offset wells and they showed good agreement. One of the principal variables of this field is the fault structures and how they affect drilling. The 3D geomechanical model concept is a complete process that allows a comprehensive analysis first in loading the grid with mechanical properties, editing the mesh, appending faults, assigning mechanical properties and finally specifying initial stress conditions like stress gradients, directions and magnitudes of horizontal principal stresses and seawater surcharge.
Tight-Gas-Sand Permeability Estimation From Nuclear-Magnetic-Resonance (NMR) Logs Based on the Hydraulic-Flow-Unit (HFU) Approach
Authors: Xiao Liang , Liu Xiao-peng , Mao Zhi-qiang , Zou Chang-chun , Hu Xiao-xin , Jin Yan 
Published: June 2014

Summary
The crossplot of porosity vs. Klinkenberg permeability (PERM) for 378 core samples, drilled from tight gas sands in the Xujiahe formation of the Anlu region-central Sichuan basin, southwest China, showed that tight-gas-sand permeability cannot be estimated effectively from porosity directly because only a poor relationship can be found between core-derived porosity and permeability because of the strong heterogeneity, especially for reservoirs with dominant microfractures (with porosities lower than 6.5%). However, the problem can be solved by introducing the HFU approach. In this paper, the 378 core samples were divided into five types on the basis of the difference of the flow-zone indicator (FZI), and then relationships of rock porosity and permeability were established for every type of core sample. By virtue of the analysis of the expression of FZI and the classical Schlumberger Doll Research (SDR) Center model, a novel technique used to obtain FZI from NMR logs was proposed and a corresponding model was established. The model parameters were calibrated by use of the laboratory NMR measurements of 54 plug samples taken from the Xujiahe formation. Carried out on the experimental data sets, this procedure can be extended to reservoir conditions to estimate consecutive formation permeability along the intervals through which NMR logs were acquired. The processing results of field examples illustrate that the calculated FZI values from field NMR logs match very well with the core analyzed results; the absolute errors among them are within the scope of 60.15. Moreover, permeability, estimated by use of the proposed technique and the core analyzed results are consistent. However, the calibrated SDR model is exclusive to the cases where formation permeability ranges from 0.2 to 0.4 md. To improve permeability prediction with the SDR model, many more core samples drilled from formations with dominant microfractures needed to be tested for laboratory NMR experiments to calibrate the SDR model for each HFU.