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Poor production results in the subject area was determined to be caused by poor reservoir contact along the laterals. In a series of wells using multi-stage plug-and-perf completions, poor perforation efficiency was diagnosed. A solution to improve formation contact was employed which made absolute contact with the reservoir by using sliding sleeves and coil tubing technology. However this system demonstrated issues mainly around lower estimated ultimate recovery (EUR) values due to wide fracture spacing limitations and also suffered occasional human related, not tool quality, failures which caused costly penalties in completing wells. Returning back to the original completion scheme re-presented the original problem that very few of the perforation clusters were opening and thus using plug-and-perf and also obtaining better perforation efficiency was re-sought.This solution step developed in this paper uses drilling data which through the use of neural networks, can generate a synthetic log. The log can yield rock properties which can generate stresses along the wellbore. These stresses are then used to select perforation spacing to better take advantage of ‘like’ stresses so that perforation opening can improve. Minimum pressure drops between perforations can then be designed. Additional information pertaining to reservoir quality was generated by adding gas chromatograph data to determine the highest permeability sections of the lateral as well as the liquid-rich hydrocarbon bearing sections. This analysis allows for a solution matrix of job and cluster spacing types to optimize fracture spacing (frequency of contact) and conductivity requirements to optimize the completion based on stress and relative or contrasting permeability.This paper will demonstrate how the problem was determined, the solution was implemented, how some alternatives were explored and how fracture geometry was greatly improved using these workflows.

This paper discusses the workflow for developing a model to predict gas production for hydraulic fracture stages in a brittle shale environment. In our last paper (SPE 163829), we developed a model to predict fracture network geometry (width, length, and height) obtained from microseismic data for various fracture treatment designs. In this study, using both microseismic data and fracture/completion data; frac treatment production is estimated. The well database used for this purpose is comprised of fracture design parameters including treatment volumes, rates, proppant mass and size; well properties include perforation interval length, and perforation depth. The goal of this study is to provide insight into factors affecting well production in a brittle shale environment. Initial data screening demonstrated massive data scattering and as a result data mining techniques are employed to find possible hidden relationships to explain the nature of the data. Also, using sensitivity analysis on the predictive model, improvements in the current fracture designs and completion schemes in Barnett shale are made. The database is examined from different aspects using various data mining approaches. After screening and preprocessing the data, non-process affected outlier wells are removed from the dataset. Then, a forward predictive neural network model is trained with fracture design and well data parameters as inputs and well cumulative gas production per stage as outputs. Neural networks are trained with the help of genetic algorithm (GA). The sensitivity study on the trained network provided many insights about well completion and stimulation strategies. Recommendations on how to improve fracture designs and well completion schemes are provided based on sensitivity analysis on the neural networks. Results of neural network modeling in Barnett shale are compared to other gas producing shale assets such as Fayetteville and Haynesville shale to compare the findings. The results of this work potentially help understanding of completion and fracture treatment designs on well productivity in gas producing shale assets. This will potentially help operators understand how to more effectively design frac treatments and/or reduce the operational costs associated with well completion in a brittle shale environment. Considering the fact that the relationship between stimulated reservoir volume and production is not entirely understood, this work may shed some lights on the aforementioned issue.

(1995). Emergence, divergence, convergence: Three models of symphony orchestras at the crossroads. The European Journal of Cultural Policy: Vol. 2, No. 1, pp. 117-139.

Introduction Suite aux nouvelles recommandations sur la prise en charge des infections urinaires (IU) communautaires de l’adulte (SPILF, 2014), nous avons souhaite realiser une enquete sur la pertinence des examens cytobacteriologiques des urines (ECBU) dans les etablissements d’hebergement pour personnes âgees dependantes (EHPAD) de la region. Methodes Une enquete retrospective par auto-questionnaire a ete realisee par les EHPAD de la region. L’inclusion s’est faite d’avril a juin 2015 a partir des ECBU envoyes au laboratoire de biologie medicale. Le questionnaire comportait une fiche reprenant les principales caracteristiques de l’etablissement et de ses residents ainsi qu’une fiche pour chaque ECBU realise (motifs, BU, prescription, realisation et antibiotherapie). Resultats Trente-deux etablissements ont participe a l’enquete. Trois cent trente-trois fiches ECBU ont ete recues. Les caracteristiques des patients etaient : âge median 87 ans (34 a 105), deux tiers de femmes (253/333) et deux tiers avec un GIR ≤ 2 (204/302). Des signes cliniques positifs etaient presents pour 72 % des patients (239/333). L’ECBU etait prescrit par le medecin dans 82 % des cas (272/332) et realise par l’IDE dans 83 % des cas (273/333). Les resultats des ECBU etaient : 62 % (207/331) positifs, 19 % (32/331) negatifs et 19 % (32/331) polymicrobiens. Les germes retrouves dans les ECBU positifs etaient principalement : Escherichia coli (66 %, 137/207), Proteus (11 %, 23/207), Klebsiella (6 %, 12/207). Une antibiotherapie etait presente chez 61 % (201/330) des patients (C3G : 31 %, 62/201, Fluoroquinolones : 29 %, 58/201). Parmi les ECBU realises, 24 % (79/333) etaient consideres comme non pertinents. Enfin, la proportion d’ECBU realises a l’initiative de l’IDE etait significativement (p = 0,03) plus importante parmi les ECBU non pertinents (25 %, 20/79) que parmi les ECBU pertinents (15 %, 38/253). Conclusion Cette enquete regionale a permis de mettre en evidence une heterogeneite des pratiques de prise en charge diagnostique et therapeutique des infections urinaires en EHPAD. Un outil d’« aide a la demarche diagnostique d’une infection urinaire du sujet âge » a ete elabore suite a ce travail.

The use of multi-stage stimulation tools to accelerate the process of stimulating horizontal wells has grown at a tremendous rate. In fact, the usage of these systems is currently underwritten by stimulation service companies because time constraints are minimized on 20-plus-stage treatments. However, using these tools can come with a cost. This paper will examine the cost benefit of using these tools in unconventional matrix and naturally fractured-based gas and oil completions. The authors will present data that will help readers choose a system to meet their needs based on their particular case. Impact on production rate and ultimate recovery, frac fluid imbibition, reduced service costs, risk in running these systems in horizontal wells and other factors will be explored.

This paper discusses a project of data mining through a database of more than 1,000 frac stages in the Barnett Shale. The database includes fracture pressure and other job data as well as the fracture shape that was mapped by microseismic processes. The original intent of the data mining project was to seek relationships between hydraulic fractures staying in zone and aiding in generating a fracture network as these events relate to net pressure trend. Results from the data mining exercise were revealing. The implications of this work potentially yield answers to questions such as: Can a frac model be developed that predicts fracture network development in a shale?Is using poroelastic-based physics in a model appropriate for shales?Can a model of this type be used to analyze frac data?What is the ultimate value of microseismic mapping in shale reservoirs? This paper is the first in a series on the database and will answer most of these questions. It will also propose future issues in the development of artificial analysis that may help select fracture network as opposed to planar frac geometry from geological and geographic data.

A holistic or overall reservoir performance perspective is seldom used in the well planning/decision process. The industry has a tendency to use broad generalizations along with uncertain interpolated reservoir information. Geologic complexity tends to turn these generalizations and assumptions into less-than-acceptable potential prospect performance predictors. In addition, the industry has a tendency to evaluate the reservoir and well drilling/completion process from a segmented or compartmentalized perspective. Numerous examples of this process exist. Petrophysicists, reservoir engineers, geologists, and drilling and completion engineers perform discrete evaluations based on their training and experiences in other reservoirs. Service companies are given incentives to concentrate on delivery/service issues and product revenue. Consultants focus on developing specific niches or completing assigned tasks. Single wells are analyzed rather than trying to understand how the well fits within the entire reservoir. Many operators grade themselves on their ability to drill and complete for less than industry standard. Their focus is on well cost. What the industry needs is an understanding of how all these issues fit into the big picture. The subject of this paper is a summary of field evaluations performed to provide a holistic perspective. Results are presented that show how these efforts have identified significant reservoir opportunities with resulting productivity and prospect economic improvement. The evaluations presented in this paper are holistic in nature and were performed by a team of experts. These evaluations consist of field data quantification, integration, enhancement, statistical and visual analysis, dimension reduction, and development of a predictive artificial neural network (ANN) model. The ANN model is used to identify patterns and trends related to the geology and to reservoir and well completion issues. Economic assessments of various completion/stimulation methods are presented. Engineering evaluations are performed to resolve difficult interpretation issues and test conclusions. The resulting information was then used to drive changes in well completion/stimulation procedures, which in some cases doubled the prospects value. This paper will illustrate the benefits of taking a holistic approach to field-wide problem solving.

In 1997, a surface modification agent was introduced into the global stimulation market. The agent was designed to enhance and sustain fracture conductivity by making the proppant surface tacky. Several conductivity-enhancing mechanisms were suggested. Two important mechanisms resulting from increased surface tackiness are 1) increased proppant pack porosity resulting in increased pack permeability and 2) increased proppant pack stability that prevents encroachment of formation fines into the pack and migration of fines within the proppant pack. In terms of extended conductivity maintenance, the fines control aspect has proved to be the most valuable property developed from the product. This paper presents a brief discussion on the theory of applying a tacky surface on proppants to mitigate conductivity loss from fines migration in the propped fracture. The paper then offers direct comparison case histories, which contain long-term production data that illustrate the benefits from lower operating expenses and increased production over the use of previous completion methods. Case histories are discussed in reservoirs that are known for fines migration, such as coal-bed methane (CBM) and high permeability-unconsolidated sandstones. The histories also include zones not widely known for fines migration problems, where the authors feel that this condition does exist.

Although fracture models are predictive, and physical measurements are accurate, both require a certain level of scientific knowledge and training to interpret and execute correctly. Based on this understanding, if we can create fracture models that are highly accurate, we can make predictions more effective and valuable. One technique makes modeling a more useful tool for designing, fine-tuning, and implementing fracturing treatments. Physical measurements of mini-fracture dimensions are input into a fracture model, allowing the model to more accurately reflect reality. After the model matches both the observed net pressure response and the directly measured hydraulic fracture geometry (the model is calibrated), the model can more closely predict the outcome of a main fracturing treatment. A survey of stimulation experts indicates that many think this step can more than double the value of using a model compared to simply using fluid-efficiency data. This paper discusses how physical measurements from a mini-frac treatment can be input into a fracturing model. Case histories will illustrate how decisions were made to alter fracturing designs and mitigate the risks associated with proppant placement.

The recent and dramatic increase in direct fracture mapping has profoundly altered our understanding of how fractures really do grow. New fracture-mapping technologies have allowed us to often directly measure what we could previously only model or assume. However, perhaps the greatest limitation of these new direct fracture-mapping technologies (tilt and microseismic) is the need for a nearby offset well in which to deploy instruments. In many environments, most notably offshore, there is often no feasible way to employ an offset observation well. Treatment well tilt mapping uses the fracture (injection) well itself as the "observation" well. The goal, quite simply, is to expand the range of environments where direct fracture mapping can be performed. The concept is simple: if fracture-induced deformation can be measured thousands of feet away at the surface or in offset wells, then it most certainly can be measured in the fracture well itself. The measurement of fracture-induced tilt versus time and depth (via an array of 4 to 20 tiltmeters) can allow robust real-time mapping of fracture height and width. Fracture length is then "modeled" based on observed height and width, and inferred fracture fluid efficiency. Treatment well tilt measurements can also provide direct measurement of mechanical fracture closure aiding, among other things, the estimation of formation closure stress. Mapping from the treatment well brings its own set of limitations and challenges. One is conducting minute wellbore movement measurements in the midst of a highvelocity flow stream. We have solved this challenge. Field data shows that the fracture-induced tilt signals in the treatment well are several orders of magnitude higher than those measured in offset wells, and they are much greater than the fluid-motion noise. The trickier challenge is deploying tools in a well during the pumping of proppant. So far we have performed real-time treatment well mapping only on fractures with clean fluid (i.e., no proppant), however, efforts are underway to overcome the difficulties with proppant. This paper provides an overview of the basic concepts, shows some real-data from treatment well applications, and presents one brief case study.

The emergence of "accepted" proppant conductivity testing methods has led to much discussion about what is needed to regain high conductivity levels, and several marketing campaigns have been based on these findings. The industry has generally accepted the principle that delivering high conductivity levels in the fracture is key to achieving high production levels. This paper does not refute this point, but modifies it. This paper presents theory, laboratory data, and case histories indicating that high initial conductivity levels can only gain high initial levels of potential or actual production. For sustained, high production levels, the proppant pack's integrity must be maintained. With time, most proppant packs are damaged by fines migration, gel clogging, and geochemical precipitation. These processes can be abated with various additives and techniques. This paper discusses these techniques in detail and shows case histories in which the techniques proved costeffective in sustaining higher levels of production than those found in comparable wells.

Results of recent field trials with a newly developed fracturing-fluid system and liquid surface-modification additive for coating proppant are presented in this paper. The work was performed in the Underpressured Fruitland Coal (UFTC) gas reservoir in the Northern San Juan Basin of Colorado and New Mexico. This new technology has influenced production in the region. Data of the test-well population are compared to the coal gas and water production from the reservoir. This study identifies and applies the new fracturing system technology for improving production. The results of this study provide information that may apply to other coal-gas reservoirs. The study group of wells uses hydraulic fracturing treatments consisting of a new low polymer loading crosslinked fluid system with a proppant surface-modification additive. The fluid system has increased crosslinked-fluid viscosity, requiring a lower gelling-agent concentration. A liquid additive that coats the proppant and increases its surface adhesion is added in the blender tub during the treatment. The surface friction between the coated proppant grains resists high flow rates during cleanup. Modifying the proppant also influences the migration behavior and blocking effects of fines (coal and precipitates) within the propped fracture.

The dewatering process, which stimulates gas desorption, is essential for gas production in coalbed methane (CBM) reservoirs. Many CBM wells require hydraulic fracturing to provide interconnectivity and hydraulic access to the cleat/matrix system. Without hydraulic communication and access to the hierar-chical flowpath, gas desorption is severely limited or nonexistent. When economics allow operators to continue long-term gas production, the gas rate of most coalbed wells will eventually increase. Over time, gas desorbs from the coal macerals that form the cleat blocks. However, some coalbed fields experience premature or severe declines in production because of poor hydraulic-fracture conductivity. Particulates have been discovered as a primary cause of poor hydraulic-fracture conductivity. These particulates flow with produced water; they are then deposited within the proppant pack where they block pore throats and interfere with gas desorption. A surface modification agent (SMA) that prevents or reduces hydraulic-fracture conductivity damage has been developed and successfully field-tested. This agent, which has strong adhesive properties, helps delay or prevent conductivity damage to the proppant bed. This paper discusses (1) the problems associated with poor hydraulic-fracture conductivity, (2) why it occurs in coalbed wells, and (3) how a new SMA can minimize the problem.

Abstract This paper discusses multiple fracture creation, detection, and prevention. Multiple fracture creation will be discussed on the basis of rock mechanics theory, laboratory experiments, and field observations. In addition, several references from SPE papers will be outlined. The section on qualitative analysis will discuss several methods of detection, ranging from core and log analysis, production history matching, and pressure transient analysis to the use of a real-time, three-dimensional (3D) fracturing model that can possibly provide quantitative analysis. Mitigation methods with regard to perforation techniques will also be briefly discussed. Introduction Poor post-fracture well performance has long been attributed to such factors as proppant convecting out of zone or poor conductivity resulting from misapplied gel-break chemistry. Although evidence suggests that such effects could worsen poor fracturing treatment performance, many fracturing treatments that result in poor production may result primarily from the creation of multiple fractures. Many stimulation engineers have yet to accept this phenomenon fully because they believe that all multiple fractures result in screenouts. Screenouts may not always occur. This paper presents a successfully executed instance in which a 3D frac model revealed a surface treating pressure that indicated eight multiple fractures. In a recent work, Mahrer et al. cited 285 articles, reports, and other documents that provided qualified observations of multiple fractures. A vigorous research of the literature was performed to discover citings of single-wing, planar fractures. With the exception of a theoretical reference by Howard and Fast, Mahrer found no references to such fractures. At the presentation of his work, however, Mahrer was besieged by several single-wing fracture constituents who would not accept his research. Mahrer proposed that the paradigm of single planar fractures should be the exception, not the norm. This paper complements Mahrer's work by exhibiting other facets of multiple fractures. In rock mechanics theory, single-fracture planes are the given norm. This postulate is easy to address numerically and conceptually. However, many cases exist in which single planar fractures were not created during experimentation with hydrostone. Although this material is considered the most manageable rock available, it allows multiple fracture initiation in nonunique circumstances. Table 1 outlines several symptoms of multiple fractures. This paper will discuss each of these symptoms and their possible causes:sand production without the placement of more than six sand grains of proppant,cyclic production performance after the fracturing treatment,shallow mineback studies,pressure behavior during stimulation, and other lesser known illustrations. A detailed section is included that discusses how to use a 3D fracture simulator to qualify and possibly quantify multiple fractures. This section will describe the differences between single-plane tortuosity and a similar effect that occurs when multiple fractures are present. Types of Multiple Fractures and Their Environments This paper will focus on multiple fractures that coalesce, overlap, or compete for the same pore space (Fig. 1). Most experts consider noncompeting fractures (Fig. 2), such as those generated when long pay intervals are fractured with several perforated intervals, as no threat to the fracture treatment's success. An example of this type of noncompeting fracture occurs in the Hugoton wells, where several members of the Chase group are being stimulated simultaneously. Multiple fractures will most likely occur in (1) naturally fractured formations, (2) long intervals of perforations, with the perforating phase being 0 >to >180, and (3) strongly dipping planes and/or deviated wellbores to flat bedding planes. P. 163^

Abstract This paper discusses processes that are common and un-common in stimulating wells which exhibit medium permeability/multilayered environments. These zones are typically found in the Texas and Oklahoma Panhandles, Southwest Kansas and Western Oklahoma. This paper ranks these processes in order of their cost effective ability to recover additional hydrocarbons from these reservoirs. In evaluating these methods, a theory will be presented which outlines the boundary mechanism in these areas. This dimension totally controls the effectiveness of the frac treatment. A method of controlling the resultant frac height in this type of environment will be offered. Value is placed upon processes such as: placing additional proppant in the zone, intense quality control, use of a leading-edge three dimensional real-time frac models, stress logs, calibration tests, reservoir evaluation prior to treatment and perforating. A field example will be cited where these processes were directly beneficial to the net present value of the well. Introduction In the history of well completions, the area of stimulating medium permeability formations or reservoirs has been the most often overlooked. By the term "medium permeability" the authors wish to specify the permeability range of 1 to 10 mDs. This range is not tight and not "loose" by most standards. In this range, the FCD starts to work against the stimulation engineer in terms of providing contrast in the pay section. This relationship: (1) states that the induced permeability of a proppant pack must be greater per unit of distance from the wellbore If this value does not increase proportionately, then placing proppant farther from the wellbore can become a non-economical option. In other words, there is an equilibrium point where "Bigger is not Better". Industry targets for this ratio are taken from Cinco's work and supplemented to fit the original Agarwal equation so that the target ratio is 31.4159. From manipulation of the relationship, one can easily see that with permeability below 1, the target ratio can easily be reached. At a permeability value of 1, the denominator quits being a "multiplier" and starts dividing into induced perm (conductivity). Since conductivity is a function of the proppant perm multiplied by the propped width, it can be increased by placing more proppant in the induced area, without making that area any longer. Conductivity contrast is lessened by placing additional proppant in excess area, however. The definition of multi-layered is self explanatory in that the productive zone is not continuous, but separated by "interior" shales or shaley pay sections, that do not produce hydrocarbons. In the Texas and Oklahoma Panhandle, Western Oklahoma and Southwest Kansas, as well as other areas, many formations exist that fit these descriptions. The successes rate in effectively stimulating them is regional, at best. However, from this should not be the case. It is to the operator's benefit that he have a well of this type, because the stimulation success is considerably easier in these formations due to the multiple layering providing permeability traps, thus bounding or, "framing" the frac treatments to generate a more elliptical shape than in unbounded formations. Stress in the interior shales is not sufficient to provide this effect. Permeability out of the perforated field becomes the more efficient bounding mechanism. There are several steps that an operator can take that directly effect the outcome of stimulation treatments in these formations. Many recent papers offer insights into building a working theory to optimize stimulation treatments in low perm formations that are bound principally by stress alone. These works offer insight in ways to place proppant more strategically in the pay section and or in the pay section and not below. In those cases, proppant convection appears to be the worst enemy that the stimulation engineer can face. P. 85

Abstract The Morrow formation in Hutchison County, Texas was long considered incapable of producing hydrocarbons at an economic rate. Most post-frac production rates were the same or less than pre-frac rates. Only high flow rate, non-stimulated completions were considered economic, but these completions were few in number. These facts lowered expectations for sufficient recovery of investment necessary to continue developmental drilling. Utilization of modern fracture model techniques, core analysis, fluid testing and stress data lead to a system of stimulation techniques, fluids and proppants that has created a cost-effective stimulation system for the Morrow formation. Lithology studies showed that the frac fluid was primarily critical to success. These studies lead to an unorthodox fluid. It contained two elements that would not be considered practical in any other formations or circumstances in the Western Anadarko basin. Proppant placement was identified as the second most important issue. Fracture height was found to be controlled by permeability, not stress. This led to the discovery that proppant convection did not allow for good proppant placement. Proppant staging methods were augmented to combat excessive convection and then acquire advantageous proppant placement. Proppant selection was identified as the third most important criteria. Reservoir stresses and modeling showed that high cost, high stress proppants were not necessary. Lower cost, larger sized proppants yielded much higher conductivity than in previous completions. These criteria were integrated into a solution which brought the post-frac production rate from a one fold to a ten fold increase. Introduction The West Arrington Morrow field of Hutchison County, Texas contains many producing horizons. One of which is the Morrow sandstone. This zone has been long overlooked for it's potential in supplying hydrocarbons due to problems in completions. Fortunately for Arrington CJM, Inc., their first three experiences with the zone were high flow rate, natural completions. Unfortunately, this was not the standard for completions to come. P. 129

The purpose of this paper is to investigate the effectiveness of vibrational stabilization for a class of linear systems with time delay. The total vibrational stabilizability conditions are formulated. The robustness of an oscillatory stabilizing effect with respect to the magnitudes of the delays and the parameters of oscillations is also investigated on the basis of numerical examples.