bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluating the Risk of Casing Failure Due to High-Density Perforation: A 3D FEM Case Study from a Deep Water Reservoir, GOM
Authors: Guo Y. , Blanford M. , Candella J. D. 
Published: October 2014

Abstract
For a deviated well planned in a highly compressible deep water reservoir in the Gulf of Mexico, a typical perforation strategy of 140° phasing with 16 shots per foot (spf) is unlikely to meet flux requirements at the anticipated production rate. Perforating the production casing twice to double the flow area is one option to avoid exceeding the maximum flux limit. But will the high-density perforations impact the casing strength enough to cause casing failure as the reservoir compacts, given the reservoir operating limits? This cannot be assessed either by using existing analytical or numerical models, or from available empirical or experimental data.
To evaluate the feasibility of using a double perforation approach, a 3D finite element (FEM) model has been developed to determine the effect of the additional holes on casing failure. The model considers variations in both casing thickness and perforation pattern under expected wellbore and reservoir conditions. Both perforated and unperforated casings were analyzed to compare casing deformation characteristics and to determine the effect of the perforation on critical depletion pressures.
The FEM model shows that casing deformation is not uniform, resulting from nonuniform strain loading across reservoir boundaries and nonuniform distribution of casing strength as a result of the perforation. For the unperforated casing, the maximum strain is associated with bending near the reservoir boundaries. In contrast, the maximum distortion of the perforated casing is concentrated around the perforation holes at the ends of the perforated intervals. Allowing for a critical strain of 6% in the casing, the depletion limit would have to be reduced from 3500 psi to 2600 psi if the second set of perforations could be applied uniformly relative to the first set. A nonuniform distribution of the second set could further reduce the casing strength and lower the critical depletion pressure to 2200 psi. Finally, the study also shows that increasing the casing thickness by 0.0625 inches would have almost no effect on casing deformation or the attendant reservoir operating limit.
The study quantifies how much casing strain to expect in the scenario described – and that is critical for evaluating the risk of casing failure in expensive deep water wells. The results suggest that models like the one described here in fact offer a feasible way to assess casing deformation in highly compressible reservoirs where high density perforation may lead to casing failure.
A New Approach to Perform a Probabilistic and Multi-Objective History Matching
Authors: Almeida Forlan La , Davolio Alessandra , Schiozer Denis José 
Published: October 2014

Abstract
Assisted history matching procedures are usually implemented within an optimization procedure, where the goal is to minimize the object function, which is written in terms of the error between observed and simulated data. One of the problems of the process is that the objective function represented by a single value is not sufficient to express the complexity of the problem. The errors that are normally measured for each well and for all production rates and pressure are converted to a single value; usually the norm of all error vectors. If the problem is well behaved and the objective function quickly converges within a desired tolerance, this would not be a problem, but this is usually not the case for complex history matching processes, since it is very difficult to find a model (or a set of them) that matches with a reasonable tolerance the production profiles for every wells. This work proposes a new approach to deal simultaneously with several objective functions (for instance, well rates and pressure). The methodology follows a probabilistic approach where several simulation models are handled during the entire procedure. The initial step is to generate several simulation models by combining the most important uncertainties of the reservoir. Then, an iterative procedure is performed to iteratively change the reservoir attributes and filter the models that are closer to history data. This procedure encompass a re-characterization step, where the probability of the attributes are updated, global multipliers are applied and local changes are made around problematic wells in order to provide a set of model that yield production and pressure curves with better dispersion compared to history data for every well. The key point of the methodology is that for every iteration the errors of each model, well and objective function can be visualized in a very concise plot that is based on the normalized quadratic error of each curve. The plot clearly shows global and local problems of the set of simulation models, so it is a good indicator of the changes to be made in the next iteration. Another point to highlight is that the same type of iterative procedure is performed to integrate 4D seismic into the process. Thus, after selecting a set of models with a good representation of well history data the same iterative process is repeated to generate a new set of models that match 4D seismic data as well. Thus, the proposed methodology integrates 4D seismic and well history data to reduce uncertainties with a probabilistic approach. To validate the methodology an application is shown where it can be seen the gradual improvement achieved for the models along the iterations.
Microseismic-Derived Correlations to Production in the Horn River Basin
Authors: Snelling Paige , Rahimi-Zeynal Asal , de Groot Michael , Hwang Kyubum 
Published: October 2014

Abstract
Production from two multilateral pads in the Horn River Basin is compared to microseismic-derived parameters. Microseismic was recorded on a near-surface array in both cases. The number of events recorded on each well tends to have a positive correlation to that well's initial production, while the magnitude of those events does not tend to be a good indicator of production in all zones. Fracture models created from located microseismic events also tend to correlate well to production: modeled fracture area, fracture volume and stimulated reservoir volume all show positive correlations.
The method in which the rock fractures can also be an indicator of initial production. Wells with higher percentages of dip-slip type rock failures, which can be associated with hydraulic fractures, tend to have higher initial production. In contrast, wells with a larger proportion of strike-slip events, which are typical of fault reactivations in this zone, tend to have diminished production compared to neighboring wells with fewer reactivation events.
By understanding what microseismic parameters positively and negatively impact initial production, operators can optimize well production. This can be done in real-time or in installments during lengthy completions programs through the identification of failure type, fracture geometry, and the relative number of events being recorded.
Diffusion and Dispersion Dominated Solvent Injection Processes in Oil Saturated Porous Media: 3-D Visualization Experiments Using Laser Technology
Authors: Fang F. , Babadagli T. 
Published: October 2014

Abstract
A technique to visualize miscible displacement in porous media is introduced in this paper. After saturating the model made of different sized glass beads with oil, solvent was introduced to mix and displace it. The refractive indices of saturated and injected fluids were made the same by mixing them with lower and higher indices of refraction. This method, called refractive index matching, made the model transparent. Fluorescent dyes that were only visible with excitation of laser were dissolved in the solvent. A laser sheet scanned the model while synchronous pictures were taken by two high speed cameras from two sides of the model. Two groups of models were worked on: (1) Solvent diffusion under purely static conditions, and (2) injection/production through a pair of horizontal wells (VAPEX type).
From the diffusion experiment, it was found that the solvent fronts were always higher close the surface of the model. It was more obvious as the model size became larger. The total diffusion time was proportional to the length of the side of the models. In the VAPEX scaled model experiment, a dome shaped solvent chamber was observed. The size of the solvent chamber decreased as distance of the injection port increased due to pressure decrease. The solvent had to spread along the top of the model before starting to displace the oil down. It is hoped that the visual observation will help in understanding the processes in the reservoir to optimize the design of solvent injection for oil recovery.
Should we Assign Different Well Performances for Low-Best Technical-High Cases in Prospect Evaluation?
Authors: Harrison Bob , Quinn Patrick 
Published: October 2014

Abstract
When creating production forecasts in order to evaluate a prospect, is it more realistic to vary the estimated well performance parameters to reflect the likelihood of the prospective resource case being modeled? For example, should wells in the high case perform better than wells in the best technical case (BTC), which in turn outperform those in the low case? If one subscribes to this school of thought, what is the most appropriate way of assigning such variation in expected well performance?
The initial rate of a well is not exclusively a function of rock and fluid properties, it also depends on completion type, formation damage, clean up practices, cement bond quality, sand control requirements, artificial lift design, coning rate constraints, to name but a few. It is regularly observed that initial well rates rarely match those suggested by theoretical calculations.
Office sweepstakes for guessing the headline flow rate from a new discovery always reveal a large range of expected initial rates and, possibly more worryingly, the reservoir engineers rarely win. Bearing this in mind, the paper goes on to ask whether it is better to simply use the same ‘average’ well performance throughout all of one's prospect analysis?
Another approach is to use the assumed geological model to divide up the prospect into good, average and poor areas and assign an appropriate well performance to each of them, based on what one believes is the reservoir quality and fluids in each prospect area.
The paper discusses the various issues confronting the reservoir engineer engaged in prospect evaluation, weighing up the arguments for changing well performance in the different cases and the arguments for leaving the well performance the same for all cases. The impact on the expected value of an exploration portfolio is discussed, depending on which approach is chosen.
Deepwater Cementing: Key Decision Process and Successful Techniques for Addressing Production Liners
Authors: Fuller George A. , Edwards Joseph , Mercado Steven , Szymanski Michael , Mead Christopher , Nguyen Cecilia , Febbraro Anthony 
Published: October 2014

Abstract
A multitude of challenges exist when cementing production liners for deepwater operations. In many platform operations, cutting windows to sidetrack and drill highly deviated well paths to intersect reservoir targets result in difficulty obtaining adequate casing standoff due to tight inside diameter (ID) restrictions from previous casing architecture. Many of the zones near the target interval may have significant pressure depletion which can lead to expensive Synthetic Based Mud (SBM) losses and associated non-productive time (NPT). The size of the production liner is dependent on the wellbore architecture and completion plan. Thus in most cases, the borehole must be under-reamed in order to provide for adequate cement sheath thickness. In these cases, centralizer selection and placement can be challenging or all together impractical. Cementing in SBM environments has also been traditionally more challenging because special considerations for spacer/surfactant/mud design and testing are required to effectively displace the mud and "water-wet" the formation/casing for good quality cement-bonding. Technology improvements in spacer and surfactant package formulations provide a more qualitative method for optimum surfactant design to maximize mud removal and provide a bonding surface to the formation. Liner hanger selection may not always provide the capability for pipe rotation which has shown to be very effective for mud removal and increased circumferential cement coverage. Without pipe rotation, additional key techniques for successful cementation must be prioritized. A process driven decision matrix is presented along with a recent selection of successful production liners to support the design concept.
A New Methodology of Selecting Sand Control Technique in Open Hole Completions
Authors: Parlar M. , Tibbies R. J. , Gadiyar B. , Stamm B. 
Published: October 2014

Abstract
Sand control technique selection in open holes has been a topic of interest since the late 90s and discussed in many papers, most comprehensively by Price-Smith et al. (SPE 85504) who proposed guidelines for selection between standalone screens, α/β packing and shunt tube packing. Proposed guidelines were based on formation characteristics (formation strength, particle size distribution, mineralogy across the well path, etc.) as well as risk (execution, reliability/longevity, etc.) and cost considerations. From a particle size distribution standpoint, their guidelines were based on the criteria proposed earlier in SPE 39437 (Tiffin et al. 1998), while risk evaluation was based on the technologies available at that time.
In this paper, we begin with a critical review of the current sand control technique selection methodologies for open-hole completions, including the way some of the risk factors are being evaluated to eliminate a given completion technique. Based on the technologies developed in the last decade, we propose a new selection methodology along with techniques/tools for proper evaluation of the risk factors. The proposed methodology significantly extends the application limits of standalone screens and α/β packing compared to what was proposed in SPE 85504 (Price-Smith et al. 2003).
Screening Criteria and Methodology for Quality Check and PVT Selection for Reservoir Studies
Authors: Paredes J. E. , Perez R. , Perera L. M. , Larez C. J. 
Published: October 2014

Abstract
In the literature, there isn't a unified criterion to establish a methodology for quality assessment of PVT analysis. Worldwide, engineers have proposed the use of well-known validation methodologies but these validation methodologies not necessarily encompasses the whole consistency of a PVT study or its representativeness of the reservoir fluids. It is well known that a PVT study might have a great consistency after it's validated but when it's used in a reservoir characterization it didn't reproduce the measured behavior of the fluid present in the reservoir. These types of inconsistencies are common and could cause very important errors in analysis such as: Original volume, reserves estimation, surface facilities planning and exploitation strategies. The impact on the results and decisions taken based on the information present in a PVT study can be crucial and therefore every PVT analysis should include a level of uncertainty index that could allow to know beforehand the cost of using such information.
The versatility and complexity of most the experiments conducted during a PVT study makes the task of creating a unique methodology of quality quantification difficult. The present paper proposes a methodology for quality control and uncertainty assessment. This methodology considers each of the stages involved in the process of obtaining a PVT analysis: from the fluid sampling to the experiments results. According to previous work and field experience, the most important parameters or conditions were selected at each stage. These parameters are called Critical Points; each Critical Point has and associated impact level (high, medium and low.) and weight that reflects directly in the overall quality index of the PVT study.
Critical points were subsequently grouped into 6 Control Categories: Sampling conditions, reservoir conditions, experiments control, measured properties control, fluid type validation and validation of experiment consistency. An ideal value of 10.0 was established for a report PVT that has excellent condition, very low uncertainty and meets all the conditions proposed in this paper. Additionally, a Quality Index (QI) and Validation Index (VI) were proposed as two indicative values of the level of uncertainty of any PVT study. Using a proposed Nomograph, engineers can evaluate and categorize the quality results from any PVT study. The results from applying this methodology to 50 PVT studies are presented and a Material Balance and numerical simulation study were carried out to exemplify the impact of using for the same reservoir, PVT from different level of quality.
The goal of this work is to have a practical methodology that can give engineers a "Quality Index" of any PVT study. This quality index could be an indicative of the level of uncertainty and the degree of reliability of the PVT study before it's subsequently used in any reservoir or well analysis. This methodology could be used worldwide without limitations
Fracture Characterization of a Carbonate Reservoir by DFN Modeling: A Case Study
Authors: Turkmen Melike Ozkaya , Gozel Mustafa Erkin 
Published: October 2014

Abstract
One of the main challenges in development of the fractured reservoirs is the identification of "sweet spots" which are the most intensely fractured areas of a field, maintaining a long term production with minimized risks in drilling. This paper presents a multi-disciplinary approach including G&G (geology & geophysics), petrophysics and reservoir engineering perspective to overcome this difficulty in a particular oil reservoir by defining the fracture systems that mainly contributes to the hydrocarbon storage capacity and flow dynamics.
Şambayat Field is one of the most important naturally fractured carbonate reservoirs located in the Southeast Turkey. Reservoir zones in the field include a number of reverse, synthetic and antithetic faults and related fracture sets which are hydraulically in contact with each other. In this context, characterizing the fracture network becomes the most critical issue in the analysis of production and the development strategy of the field.
For this purpose; besides the conventional open-hole log analyses, image log interpretations have also been performed in order to evaluate the properties of the fractures. To honor these interpretations; dynamic (drill stem test & production) and static (outcrop & core) data have been evaluated together. Distributions of the petrophysical properties and the fractures have been done by using stochastic methods in full-field scale. At the end of the modeling study, a dual porosity geological model has been generated by using the Discrete Fracture Network (DFN) approach with respect to the estimated fracture characteristics.
As the result of the previous characterization study, new well locations and their optimized orientations had been determined and the results coincided with the expected types of fractures estimated in the DFN model. After updating the model with the new well data and the enhanced functionalities in the modeling software, additional well locations have been proposed which will play a role in one step further of the study; simulation.
This study has contributed to our knowledge about the characteristics of a naturally fractured carbonate reservoir which is similar to the ones explored in Southeast Turkey and to some extend in Middle East. It should also be noted that, our approach in this particular study is a newly developing technique and could be used for the promising "previously overlooked" unconventional reservoirs.
Acoustical and Geomechanical Characterization of Eagle Ford Shale - Anisotropy, Heterogeneity and Measurement Scale
Authors: Mokhtari M. , Honarpour M. M. , Tutuncu A. N. , Boitnott G. N. 
Published: October 2014

Abstract
In this study, the acoustical and geomechanical properties of preserved cores and the associated well logs from the lower Eagle Ford shale in La Salle County, Texas are presented. Anisotropy is evaluated using measurements at various scales: at the pore scale by scanning electron microscopy (SEM), at the lamination scale by compressional velocity scanning and x-ray computed tomography (CT) imaging and at the core scale via static/dynamic measurements on both 1-inch and 3-inch diameter cores. Finally, correlations from core data are applied to sonic log interpretation to improve the estimation of minimum horizontal stress in a vertical transverse isotropic media.
Three sets of horizontal and vertical 3-inch core samples were prepared from conventional cores in the light oil-bearing section of the lower Eagle Ford shale. Compressional velocities were measured every 0.5 mm to examine vertical heterogeneity at the lamination scale on 3-inch horizontal cores. In one of the samples, frequent thin layers with higher velocity (+15%) were detected. The high velocity layers correspond to foraminifera rich layers detected in the SEM analysis. These layers are source of vertical heterogeneity which can affect the anisotropic analysis.
Dynamic testing on the 3-inch cores was conducted followed by dynamic testing on 1-inch plugs (horizontal, vertical and 45°) drilled from each of the 3-inch cores and a comparative study between the 1-inch anisotropic results with their 3-inch counterparts was conducted. Shear and compressive anisotropy was similar between the 3-inch and 1-inch samples detected homogenous by velocity scanning. On the other hand, there was significant difference between the anisotropic parameters in the heterogeneous sample containing frequent foraminifera rich layers.
Using core data, correlations for the two unknowns of sonic logs (C13 and C12) and the dynamic to static correlations were obtained and applied in the calculation of elastic properties from logs. Consequently, the conventional minimum horizontal stress with isotropic media assumptions was modified by the core-derived correlations and anisotropic Biot's coefficient.
The results of this study determine how the heterogeneity due to lamination and scale can significantly affect anisotropic analysis. Finally, we discuss how to use more accurate experimental data to estimate the minimum horizontal stress from sonic logs using transverse isotropic modeling in the Eagle Ford shale.