bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Peripheral Blood Leukocytes in Patients With Cyclosporine A‐Induced Gingival Hyperplasia
Authors: Cebeci Írfan , Kantarci Alpdoǧan , Gürel Nuray , Adin Suzan , Tuncer Özen , Çarin Mahmut , Badur Selim , Firatli Erhan 
Published: March 2012

Background: Gingival overgrowth is one of the major adverse effects of the immunosuppressive drug cyclosporine A (CsA). Although several studies have attempted to determine the immunological mechanisms of gingival hyperplasia (GO) due to CsA therapy, the pathogenesis remains unclear. In this study, the distribution of the peripheral blood leukocytes in a group of renal transplant patients undergoing CsA therapy was analyzed and possible correlations of periodontal and pharmacological variables to lymphocyte subpopulations, natural killer cells, and monocytes investigated.Methods: Thirty‐six patients were classified into 2 groups of 18 each according to the degree of gingival overgrowth. The periodontal evaluation included plaque index (PI), gingival index (GI), gingival overgrowth (GO), calculus index (CI), and probing depth (PD). The pharmacological variables of current doses of the therapeutic serum levels of CsA were investigated. The peripheral blood leukocytes were studied by 2color flow cytometric analysis using anti‐human CD2, CD3, CD4, CD8, CD11b, CD11c, CD16, CD19, HLA‐DR, and CD3+HLA‐DR+ monoclonal antibodies.Results: Statistical evaluation revealed that none of the pharmacological variables varied between the 2 groups. Responders (GO >30%) had significantly higher GI, PD, and GO scores compared to nonresponders (GO ≤30%). Of the immunological parameters studied, only CD2 was higher in the responder group. None of the clinical parameters correlated to the immunological values.Conclusions: The results of this study may be useful in explaining the underlying mechanisms of drug‐induced gingival overgrowth. Several previously unsuspected cells and accessory activation mechanisms for T lymphocytes could play a role in the pathogenesis. J Periodontol 1998;69:1435–1439.
Maximize Placement of Wells and Production in Unconventional Reservoirs: Part 2
Authors: Holdaway Keith Richard 
Published: March 2012

Abstract
Over the past decade, significant supplies of natural gas have been discovered in shale. While the development of new technologies has driven down the cost of gas extraction, pursuing natural gas in shale continues to be risky and capital-intensive.
Producers seek the most productive zones in their unconventional basins, as well as continued improvement in hydraulic fracturing processes. Decreasing costs and reducing risk while maximizing gas production necessitates innovative, advanced analytical capabilities that can give you a comprehensive understanding of the reservoir heterogeneity in order to extract hidden predictive information, identify drivers and leading indicators of efficient well production, determine the best intervals for stimulation, and recommend optimum stimulation processes and frequencies. Modeling, simulating and predicting well productivity requires integrated exploratory, predictive and forecasting capabilities underpinned by advanced analytical models to unlock the true potential of each wellbore. Without the critical insight enabled by integrated analysis to pair productivity analysis with economic feasibility, companies face significant risk and uncertainty when developing new wells or optimizing production of extant wellbores.
This paper walks through a case study implemented in the Barnett asset in the United States, exemplifying data mining workflows that successfully improved hydrocarbon production. We shall detail analytical methodologies to explicate the optimization of these assets as additional to those workflows expanded upon in SPE paper 149784 presented in Abu Dhabi at the Middle East Unconventional Gas Conference and Exhibition.1
Stimulation Unlocks Coalbed Methane: Lessons Learned in India
Authors: Pooniwala Shahvir Aspi 
Published: March 2012

AbstractAlthough gas production from coalbed methane (CBM) wells has become an important source of energy in North America over last couple of decades, it still remains an upcoming area in India. India has the fourth-largest proven coal reserves in the world and therefore considerable prospects exist for exploration and exploitation of CBM. Development of CBM and other unconventional gas sources are currently a priority for India to meet its growing energy demand.An effort has been made in this paper to review the lessons learned from the stimulation and production of Raniganj CBM field in India. Experiences from large number of CBM operations in the US and Australia have been useful in this regard, however several constraints specific to India had to overcome to make the campaign successful: India is an extremely cost-sensitive market.Location sizes are limited, making the logistics very challenging.Land acquisition problems, resulting in different drilling and field development strategies employed.Seasons/weather challenges in the northeastern part of India, where most of the CBM blocks are located.Proppant flowback is a problem due to lower closure stress.This paper will review over 150 recent hydraulic fracture treatments in CBM wells in India. It will summarize different drilling and perforation strategies, completion practices, hydraulic fracturing design considerations, job execution, difficulties faced and solutions employed in India to overcome the difficulties. It will conclude with lessons learned that can be applied in future wells.
Casing Centralization in Horizontal and Extended Reach Wells
Authors: Sanchez Alfredo , Brown Christian F. , Adams Whitney 
Published: March 2012

AbstractLong laterals being drilled today present new challenges in getting casing to bottom and achieving good zonal isolation. Casing centralizers play a key role in achieving these objectives and should be evaluated differently than they have been in the past.A comprehensive methodology for evaluating, selecting, and running casing centralizers is described. This method is based on analyzing downhole conditions (formation type, borehole stability, etc.) in conjunction with specific drilling practices (bottom hole assembly design, hole cleaning procedure, etc.) to arrive at an optimum casing centralization program that will meet cementing objectives.A manufacturer and an operator share their experience in the application of comprehensive centralization placement and torque and drag modeling. Also discussed is the evaluation and selection of casing centralizers including practices to increase the accuracy of these simulations. Particular emphasis is given to rotation while running and cementing casing. Post job analysis of actual rig data is discussed in an effort to arrive at more accurate friction factors for future wells.In addition, custom laboratory testing and evaluation of running and restoring forces of bow-type centralizers is discussed.The approach described in this paper can help reduce the compromise between getting casing to bottom and achieving good zonal isolation.
Testing Tight Gas and Unconventional Formations and Determination of Closure Pressure
Authors: Soliman M. Y. , Gamadi Talal 
Published: March 2012

Abstract
Experience indicates that applying the conventional testing techniques such as drawdown-buildup tests to unconventional reservoir may lead to non-unique answers. Diagnostic testing approach is now more commonly used in tight gas formations and unconventional reservoirs. Testing unconventional reservoirs, particularly hydrocarbon-bearing shale formations, presents considerable challenges. In addition determination of the fracture closure pressure is sometime elusive. This paper reviews those challenges faced in analysis of testing of tight gas and unconventional reservoirs both liquid and gas. Conventional testing and analysis methods, although applicable, are often impractical because of excessive test duration. Diagnostic fracture injection test (DFIT) has become the preferred option for unconventional formations. Several methods may be used for interpreting DFIT data. We examine those methods in detail and explore their relative strengths while interpreting field data. We also show ways to determine the fracture closure pressure under various reservoir and fracture conditions.
Effect of Sand Lens Size and Hydraulic Fractures Parameters on Gas in Place Estimation Using ‘P/Z vs Gp Method’ in Tight Gas Reservoirs
Authors: Bahrami Hassan , Rezaee Reza , Hossain Mofazzal , Murickan Geeno , Basharudin Naqiuddin , Alizadeh Nasser , Fathi Afshin 
Published: March 2012

Abstract
Low permeability and complexities of rock formation in tight gas reservoirs make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional reservoirs in the case that formation rock is not sensitive to damage caused by liquid invasion, hydraulic fracturing is the most common stimulation treatment to improve the production to the excepted economically rate. In term of reservoir geometry, tight sand formations are normally consisted by the stacks of isolated lenses of sand bodies that are separated by impermeable layers (e.g. shale). Each sand lens varies in shape and size and acts as a trap for original hydrocarbon accumulations. The sand lenses parameters such as length and width can play important role in controlling gas recovery from hydraulically fractured tight gas reservoirs.
This study shows the effect of drainage pattern of the lenticular sand bodies on production performance, gas in place (GIP) estimation using P/Z vs Gp method, and ultimate gas recovery in tight gas formations. Numerical simulation approaches are used in order to understand the effect of hydraulic fracture parameters and also attribution of sand lens size and shape to the drainage pattern and gas recovery in hydraulically fractured tight sand gas reservoirs.
The results highlighted that in tight gas reservoirs, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Drainage of gas from the reservoirs is controlled by the sand lens width, and the size of sand lenses in the direction parallel to the hydraulic fracture wings does not have significant effect on gas recovery. The drainage area of the tight gas reservoirs is limited to the area perpendicular to the hydraulic fractures wings, and therefore P/Z vs Gp method may underestimate the value of GIP calculated for the lenticular/elliptical shape sand lenses.
Diagnosing Fracture Network Pattern and Flow Regime Aids Production Performance Analysis in Unconventional Oil Reservoirs
Authors: Rasdi Faisal , Chu Lifu 
Published: March 2012

Abstract
Many tight or shale gas wells exhibit a linear flow regime that can last for years. However, production analysis in unconventional oil reservoirs, such as the Bakken, shows that the linear flow regime is not the only dominant flow regime. Field data suggest that the duration of boundary-dominated flow influenced by the stimulated-reservoir volume (SRV) and compound-linear flow generally overshadow the early-time linear flow regime. Depending on the fracture network or SRV patterns, formation linear flow in unconventional oil reservoirs may only last for a few months but contribute about 30% of the total estimated ultimate recovery (EUR).
This study develops a procedure for identification of different fracture network patterns and inference of related flow parameters based on analytical methods. The reservoir description so derived is transported to a numerical reservoir-flow simulation model to capture the effects of compaction, multiphase flow behavior, and various flow regimes in an unconventional oil reservoir system.
This coupled approach helps illuminate reservoir performance, which allows insights into history matching. In particular, we demonstrate (a) fracture network patterns and flow regime diagnosis through rate-transient analysis; (b) coupled numerical reservoir simulation with analytical modeling results for performance-constrained history matching; (c) sensitivity analysis on the heterogeneity effect, compaction effect, and multiphase flow effects; and (d) field application of the proposed procedure on Bakken wells.
This proposed method demonstrates that analytical methods should be used before undertaking a detailed numerical reservoirflow simulation study. This understanding paves the way for much improved reservoir characterization in unconventional oil reservoirs.
New Inflow Performance Relationship for Coalbed Methane Wells
Authors: Feng Qihong , Shi Hongfu , Zhang Xianmin , Du Peng , Zhang Jiyuan 
Published: March 2012

AbstractThe inflow performance relationship (IPR) plays an important part in well completion, well production optimization, nodal analysis calculations, and artificial lift design. The production of coalbed methane is different from the conventional gas. For coalbed formation, permeability is sensitive to changes in effective horizontal stress which includes a cleat compression term and a matrix shrinkage term that have competing effects on cleat permeability. Therefore, the conventional method to calculate IPR curve is not completely appropriate for coalbed methane.The production of under-saturated coalbed methane reservoir can be divided into three distinct stages-: single water phase, multiphase gas and water, and single gas phase. Previous literatures either neglect the matrix shrinkage which results in increasing production rate at a given bottom hole pressure or only focus on the last single gas phase stage.This paper presents a new method to calculate the IPR curve for coalbed methane reservoir in the presence of permeability dynamics with pressure based upon P&M or Shi model. A second objective of this paper is to develop an approach for multiphase flow which requires a relationship between relative permeability and pressure, analogous to Fetkovich’s method for oil and gas flow.The methodology is further validated with field data from Qinshui Basin in China. The results indicated that the tool proposed here provides reservoir enginners with a quicker and easier way to estimate the performance of coalbed methane well.
Modelling Of Hydraulic Flow Characteristics In Depleting Tight Gas Reservoirs
Authors: Albrecht D.. , Reitenbach V.. 
Published: March 2012

Abstract
Fluid flow properties of tight Rotliegend sanstones show a strong sensitivity to stress conditions. To improve the understanding how fluid flow properties depend on the stress situation experimental measurements have been conducted on low to ultra-low Rotliegend sandstone samples from a North-German gas reservoir under simulated reservoir stress conditions. The measurements have been performed in the project DGMK 593-9/4 in the framework of the tight gas program of the DGMK (German Society for Petroleum and Coal Science and Technology). From the results of the experiments models could be derived, which describe the stress dependency of permeability and porosity.
The experimental study improves the understanding of stress dependence behavior of low permeable North-German sandstones and provides relevant reference data for simulation of flow processes. The correlation models based on the experimental results presented enable the evaluation of representative in-situ effective stress, permeability and porosity in low permeable Rotliegend sandstones from routine laboratory permeability and porosity data as well as depletion effects during the gas production.
Perforating on Wireline – Weak-Point Load Prediction
Authors: Baumann Carlos , Benavidez Marcia , Martin Andy , Salsman Alan , Williams Harvey 
Published: March 2012

AbstractThousands of wireline conveyed perforating jobs are executed every month around the world; however certain jobs have a higher risk of weak-point breakage due to dynamic pressure loads, known as gunshock loads. Gunshock loads result from pressure waves in fluids and stress waves in structural components. Perforating under all conditions (i.e. static/dynamic overbalance or underbalance) can produce pressure waves and/or reservoir surge of large magnitude leading to wireline weak-point (WWP) failures and/or cable damage. These risks are assessed as part of the job preparations. In this paper we focused on Dynamic Underbalance (DUB) because perforating with DUB can deliver clean perforations with very low risk of gunshock damage when properly planned.For any perforating job on wireline, the magnitude and duration of pressure and stress waves depend on job parameters that can be adjusted, such as type and size of guns, shaped charges, gun loading layout, wellbore fluid, placement of packers and plugs, and cable size. For perforation damage removal we need a job design to generate a DUB of enough magnitude, using the right gun types and loading to produce a DUB of large-amplitude but short-duration, thus removing perforating rock damage while minimizing gunshock loads on the WWP. Perforating job designs are evaluated with software that predicts the transient fluid pressure waves in the wellbore and the associated structural loads on the cable and tools. All aspects of well perforating are modeled including gun filling, wellbore pressure waves, wellbore and reservoir fluid flow, and the dynamics of all relevant solid components like cable, shock absorbers, tools, and guns.When planning perforation jobs that may have a significant risk of weak-point breakage, we predict the peak dynamic loads on the cable and weak-point during the design process, and when necessary we make design modifications to reduce the peak load on the WWP. The software’s predictive capabilities are demonstrated by comparing downhole fast gauge pressure data (110,000 data points per sec), shock absorber deformation, and cable tension logs with the corresponding simulated values. Fast gauge pressure data from perforation jobs shows that the software predictions are sufficiently accurate to evaluate the gunstring dynamics and the associated peak tension load on the WWP as part of the job planning process. Residual deformation of shock absorbers correlate well with predicated peak axial loads at the WWP, and available cable tension logs from vertical wells show that the cable surface tension is well predicted.The simulation software described in this paper is used to minimize the risk of unexpected release of tools and guns due to perforating dynamic loads, thereby minimizing the probability of non-productive time (NPT) and fishing operations.
A New Approach for Numerical Modeling of Hydraulic Fracture Propagation in Naturally Fractured Reservoirs
Authors: Keshavarzi R.. , Mohammadi S.. 
Published: March 2012

Abstract
Hydraulic fracturing of a naturally fractured reservoir is a challenge for petroleum industry, as fractures can have complex growth patterns when propagating in systems of natural fractures that leads to significant diversion of hydraulic fracture paths due to intersection with natural fractures which causes difficulties in proppant transport. In this study, an eXtended Finite Element Method (XFEM) model has been developed to account for hydraulic fracture propagation and interaction with natural fracture in naturally fractured reservoirs including fractures intersection criteria into the model. It is assumed that fractures are propagating in an elastic medium under plane strain and quasi-static conditions. The results indicate that hydraulic fracture diversion before and after intersecting with natural fracture is strongly controlled by the in-situ horizontal differential stress and the orientation of the natural fractures as well as hydraulic fracture net pressure. It is observed that hydraulic fracture net pressure increase leads to decreasing induced fracture diversion and in-situ horizontal differential stress decrease results in increasing induced fracture diversion before intersecting with natural fracture. In addition, potential debonding of sealed natural fracture in the near-tip region of a propagating hydraulic fracture before fractures intersection has been modeled which is one of the phenomena that has been rarely taken into account, as debonding of natural fracture before fractures intersection is of great importance that may lead to diverting the induced fracture into double-deflection in natural fracture and can explain hydraulic fracture behaviors due to interaction with natural fracture at different conditions. Also, it’s been observed that at low angles of approach with low to high differential stress, the induced hydraulic fracture opens the natural fracture while at high to medium angles of approach, natural fracture opening and crossing both are observed depending on the differential stress. Comparison of the numerical and experimental studies results has shown good agreement.
Permeability Upscaling for Carbonates from the Pore-Scale Using Multi-Scale Xray-CT Images
Authors: Khalili A. D. , Arns C. H. , Arns J. -Y , Hussain F.. , Cinar Y.. , Pinczewski W. V. , Latham S.. , Funk J.. 
Published: March 2012

AbstractHigh-resolution Xray-CT images are increasingly used to numerically derive petrophysical properties of interest at the pore scale, in particular effective permeability. Current micro Xray-CT facilities typically offer a resolution of a few microns per voxel resulting in a field of view of about 5 mm3 for a 20482 CCD. At this scale the resolution is normally sufficient to resolve pore space connectivity and transport properties. For samples exhibiting heterogeneity above the field of view of such a single high resolution tomogram with resolved pore space, a second low resolution tomogram can provide a larger scale porosity map. The problem then reduces to rock-typing the low resolution Xray-CT image, deriving viable porosity-permeability transforms from the high resolution Xray-CT image(s) for all rock types present, and upscaling of the permeability field to derive a plug-scale permeability.In this study we characterize spatially heterogeneity using overlapping registered Xray-CT images derived at different resolutions spanning orders of magnitude in length scales. A 38mm diameter carbonate core is studied in detail and imaged at low resolution - and at high resolution by taking four 5mm diameter subsets, one of which is imaged using full length helical scanning. Fine-scale permeability transforms are derived using direct porosity-permeability relationships, random sampling of the porosity-permeability scatter-plot as function of porosity, and structural correlations combined with stochastic simulation. A range of these methods are applied at the coarse scale. We compare various upscaling methods including renormalization theory with direct solutions using a Laplace solver and report error bounds.We find that for the heterogeneous samples permeability typically increases with scale. Conventional methods using basic averaging techniques fail to provide truthful vertical permeability due to large permeability contrasts. The most accurate upscaling technique is employing Darcy’s law. A key part of the study is the establishment of porosity transforms between high-resolution and low-resolution images to arrive at a calibrated porosity map to constraint permeability estimates for the whole core.