bluuebunny/crossref_metadata_2025_split huggingface dataset:
Therapy of Endocrine disease: Long-term effects of recombinant human GH replacement in adults with GH deficiency: a systematic review
Authors: Appelman-Dijkstra Natasha M , Claessen Kim M J A , Roelfsema Ferdinand , Pereira Alberto M , Biermasz Nienke R 
Published: April 2013

BackgroundThe beneficial effects of recombinant human GH (rhGH) therapy in GH deficient (GHD) adults are well-established in the short term. However, data documenting the effects during prolonged follow-up are relatively scarce.ObjectiveTo evaluate the reported effects of rhGH replacement (≥5 years) in GHD adults on biochemical and anthropometric parameters, quality of life (QoL), bone metabolism, muscle strength, serious adverse events and mortality.MethodsWe conducted a systematic literature search. Quality assessment of retrieved papers was performed using a quality assessment based on the modified STROBE statement.ResultsWe included 23 prospective studies with a rhGH treatment duration ranging from 5 to 15 years. Overall, beneficial effects were reported on QoL, body composition, lipid profile, carotid intima media thickness and bone mineral density. In contrast, the prevalence of the metabolic syndrome, glucose levels, BMI and muscle strength were not, or negatively, influenced. Most of the studies were uncontrolled, lacked the presence of a control group (of non-treated GHD patients), and reported no data on lipid-lowering and anti-diabetic medication. Overall mortality was not increased.ConclusionrhGH treatment in adult GHD patients is well-tolerated and positively affects QoL in the long term. However, the metabolic and cardiovascular effects during long-term treatment are variable. The low numbers of long-term studies and studied patients and lack of control data hamper definite statements on the efficacy of prolonged treatment. Therefore continuous monitoring of the effects of rhGH replacement to enable an adequate risk-benefit analysis that may justify prolonged, potentially life-long, treatment is advisable.
Metformin inhibits goitrogenous effects of type 2 diabetes
Authors: Ittermann Till , Markus Marcello R P , Schipf Sabine , Derwahl Michael , Meisinger Christa , Völzke Henry 
Published: April 2013

ObjectiveData on the association between type 2 diabetes mellitus (T2DM) and thyroid volume are sparse. An experimental study demonstrated an inhibitory effect of metformin on the growth of human thyroid cells. So far no study on humans has investigated potentially modulating effects of metformin on the association between T2DM and thyroid volume. Therefore, we investigated these effects in a population-based cohort study.Design and methodsWe used data from the Study of Health in Pomerania and included 2570 individuals for cross-sectional and 1088 individuals for longitudinal analyses. T2DM was defined by physician-diagnosed self-report or intake of antidiabetic medication.ResultsIn the cross-sectional data, females with T2DM treated with antidiabetic medication other than metformin had a larger thyroid volume (β=4.69; 95% CI 1.87 to 7.50) and a higher odds ratio (OR) for goiter (OR=1.71; 95% CI 1.05 to 2.79) than females without T2DM, whereas in males, no such association was detected. In females or males treated with metformin, T2DM was not associated with thyroid volume or goiter. In longitudinal analyses, incident T2DM not treated with metformin was significantly associated with a higher risk for incident goiter in the total population (incidence rate ratio (IRR)=1.70; 95% CI 1.10 to 2.91). Individuals with T2DM having changed from metformin to other antidiabetic agents during follow-up also had a higher risk for incident goiter than individuals without T2DM (IRR=2.71; 95% CI 1.74 to 4.20).ConclusionsWe demonstrate an inhibitory effect of metformin on prevalent and incident goiter. Anti-goitrogenous effects of metformin add to the general benefits of metformin treatment of T2DM.
A Superior, High-Performance Enzyme for Breaking Borate Crosslinked Fracturing Fluids Under Extreme Well Conditions
Authors: Zhang Bin , Huston Adrienne , Whipple Lawrence , Urbina Hugo , Barrett Ken , Wall Mark , Hutchins Rick , Mirakyan Andrey 
Published: April 2013

Summary
Enzyme breakers have been previously used for hydrolyzing guar gels at temperatures below 150°F. There is an industry-wide demand for enzyme breakers that can function under higher-temperature (200–250°F) and extreme pH (≥10.5) conditions. To meet this demand, efforts have been made to develop an exceptionally thermostable cellulase enzyme, referred to hereafter as mannanase, that was originally discovered in a hydrothermal vent sample. This mannanase exhibits well-differentiated performance under extreme downhole conditions encountered in gas shales and deeper oil/gas wells.
This superior mannanase can effectively break linear and borate crosslinked guar under broad ranges of temperature (80°F up to at least 225°F as seen by rheology, and up to 275°F using residual activity analysis) and pH (3.0 up to 10.5). The results of rheological tests show that only a small dose is required (100 ppm or less) to achieve the complete break. The enzymatic reaction can be triggered by the changes of temperature and pH during fracturing operations. This mannanase also exhibits a dose response that allows the operator to generate a desirable viscosity/time profile by adjusting enzyme dosage. Even in the presence of fluid additives, such as buffers, salts, stabilizers, and crosslinkers, this mannanase is active for effective viscosity reduction.
This mannanase breaker belongs to the glucanase family. It reduces gel viscosity by specifically targeting β-1,4 glycosidic bonds between the mannose units in guar. The carbohydrate-profiling tests demonstrate that this enzyme effectively and efficiently breaks the long-guar polymers into small, soluble fragments that will eliminate gel rehealing. The conductivity tests demonstrate extensive cleaving of guar and removal of polymer residues that cause formation damage and reduce fracture conductivity.
Is That Radial Flow? What Can be Learned From Buildup Analysis of Multiply-Fractured Horizontal Wells In Unconventional Reservoirs
Authors: Lougheed D. , Santo M. , Ewens S. 
Published: April 2013

Abstract
Buildup data from multiply-fractured horizontal wells (MFHW) in tight (micro to nano-Darcy permeability) unconventional reservoirs often display a derivative signature which appears like radial flow and is frequently misinterpreted as such without due consideration of the expected flow regimes from these systems. Studies based on both numerical and analytical modeling suggest that radial flow regimes will not be observed, due to the large number of hydraulically induced fractures, and the geometry of a typical MFHW completion. Analysis of production data continues to show no evidence of radial flow, but instead, reveals that linear flow regimes dominate for the majority of a well's lifetime. This is more consistent with the expected flow behavior, and leads to confusion on how to interpret buildup data that often appear like radial flow. This paper provides explanations for the different pressure behavior exhibited during a buildup. In doing so, the value of conducting a buildup test to assess the reservoir characteristics and completion effectiveness, is demonstrated. Two examples of actual buildup data obtained from MFHWs completed in unconventional reservoirs are presented to support the findings of this paper.
Analytical and Numerical Solutions for Multiple-Matrix in Fractured Reservoirs: Application to Conventional and Unconventional Reservoirs
Authors: Torcuk Mehmet A. , Kurtoglu Basak , Alharthy Najeeb , Kazemi Hossein 
Published: April 2013

Abstract
In this paper we present a new method to model heterogeneity and flow channeling in petroleum reservoirs—specially reservoirs containing interconnected microfractures. The method is applicable both to conventional and unconventional reservoirs where the interconnected microfractures form the major flow path. The flow equations, which could include flow contributions from matrix blocks of various size, permeability and porosities, are solved by the Laplace transform analytical solutions and finite-difference numerical solutions. The accuracy of flow from and into nano-Darcy matrix blocks is of great interest to those dealing with unconventional reservoirs; thus, matrix flow equations are solved using both pseudo-steady- state (PSS) and un-steady-state (USS) formulations and the results are compared.
The matrix blocks can be of different sizes and properties within the representative elementary volume (REV) in the analytical solutions, and within each control volume (CV) in the numerical solutions. While the analytical solutions were developed for slightly compressible rock-fluid linear systems, the numerical solutions are general and can be used for non- linear multi-phase, multi-component flow problems.
The mathematical solutions were used to analyze the long-term performance of a gas well and an oil well in two separate unconventional reservoirs. Finally, the formulations were used to assess enhanced oil recovery potential from a typical nano- Darcy matrix block. It is concluded that matrix contribution to flow is very slow in a typical low-permeability unconventional reservoir and much of the enhanced production is from the fluids contained in the microfractures than in the matrix.
In addition to field applications, the mathematical formulations and solution methods are presented in a transparent fashion to allow easy utilization of the techniques for reservoir and engineering applications.
Understanding Unconventionals by Multidisciplinary Integration - A Microseismic Based Tale of the Haynesville Shale
Authors: Gangopadhyay Abhijit , Malayalam Atif , Lucas Jennifer , Gillham Travis , Liu Shujie , Faz Ignacio , Wirnkar Fabian 
Published: April 2013

Abstract
Microseismic data acquired using a near-surface array in four horizontal wells in the Haynesville shale in Shelby and San Augustine counties, Texas, were analyzed and integrated with geoscience, petrophysics, completions, and flow-back performance data. Horizontal sections of the wells are ~5,000 feet long, and stimulated with twelve stages. Analyses of microseismic events from the first two wells to understand fracture containment, led to drilling the fourth as a transverse across the target zone. A production log was also run in the same well to identify zones in the Haynesville that produced the highest rate of gas. Fewer microseismic events were recorded during stimulations of the northward wells, and resulting fractures were more elongated than the southward wells. Fracture half-lengths based on all located microseismic events from the four wells range between ~400 feet and ~700 feet. The derived fracture orientations are consistent with the regional SHmax and confirm our choice of well azimuths. Some prominent fractures align with those inferred from 3-D seismic based coherency attribute, indicating that pre-existing fractures were activated. Correlations of microseismic event locations with gamma ray logs along the laterals revealed that fractures initiated better when the log values are &lt;110 API, an observation consistent with Lithology-based brittleness index. The completions strategy included pumping resin coated sand in one well, combining that with white sand in others, and stimulating the shortest lateral with the same proppant volume and stages as others. Flow-back performance of the shortest lateral was strong enough to suggest the potential for reserve improvement by shortening stage length. The interpreted production log shows that stages near the heel are most productive compared to the first three stages near the toe, leading to an estimate of the effective stimulated rock volume. Summarily, the study provides multidisciplinary insights into future horizontal designs in the area.
Time Dependent Fracture Interference Effects in Pad Wells
Authors: Manchanda Ripudaman , Sharma Mukul M. , Holzhauser Shawn 
Published: April 2013

Abstract
Hydraulic fracturing in shale formations induces microseismic events in a region we refer to as the microseismic volume. Many of these microseismic events are signatures of failure in the formation that are believer to be a result of induced fractures, beyond the primary propped fracture. Aerially extensive microseismicity may be evidence that these induced, unpropped fractures occur and extend spatially beyond the propped fracture in many unconventional reservoirs.
To illustrate these effects, microseismic and radioactive tracer data is presented for four laterals drilled and fractured from a single pad. Our simulations show that the opening of these induced, unpropped fractures results in significant temporary changes to the stress field in the rock. One consequence of this is that later fracture stages tend to propagate into the open fracture networks of induced, unpropped fractures created earlier due to stress reorientation. This can lead to inefficient usage of time, fluid, proppant, and capital since the region being stimulated has already been stimulated by the previous stage. By analyzing the net pressure, radioactive tracer and microseismic data from the four-well pad, we show that these induced, unpropped fractures close over time (over a period of hours) as the fracture fluid leaks-off. This relaxes the stresses and subsequent induced fractures are no longer subjected to the significantly altered stresses, allowing for more efficient fracture network coverage by subsequent fractures in a horizontal well. Based on the data presented and computer simulations, we propose the idea of establishing a minimum time between fracturing in the microseismic volume of a recently fractured region. The time required for the induced unpropped fractures to close can be calculated from our models and varies based on the reservoir and fluid properties but is typically on the order of hours. One example of how this is accomplished in practice is zipper fracs. However, our work suggests that there may be other fracture sequencing strategies for accomplishing this as well.
Relationship Between Organic Shale Microstructure and Hydrocarbon Generation
Authors: Curtis M. E. , Sondergeld C. H. , Rai C. S. 
Published: April 2013

Abstract
Interest in shale resource plays has shifted from gas to gas condensate and oil because of economic pressures. From a geochemical perspective, this represents a shift in thermal maturity of the organic matter in the host rock. It is believed that the development of secondary nanoporosity in the organic matter is linked to the thermal maturity of the shale; therefore thermal maturity has an effect on both storage and permeability in plays dominated by organic porosity. Previous research on thermal maturity and organic porosity in gas shales shows a trend of porosity occurring in the gas window (&gt; 1.2% Ro); however, to date, few investigations of microstructure in the oil window have been carried out.
To investigate the organic porosity in low thermal maturity shale samples, a combination of Focused Ion Beam (FIB) milling and Scanning Electron Microscopy (SEM) was utilized. This combination permits careful sample preparation that preserves the microstructure, minimizes artifacts, and provides the ability to image the nanoscale organic pores which are below the resolution of visible light. Initial FIB/SEM results on oil window shale samples suggest a completely different type of porosity development within organic matter in the oil window (~0.6-1.0% Ro) versus the gas window. Oil window porosity development in the organic matter is exhibits crack-like features that appear to be a product of hydraulic fracturing and shrinkage of organic matter. This is in stark contrast to the porosity observed in gas window shales.
The crack-like features observed in the organic matter of oil window shales have immediate implications for local expulsion of oil. Excess oil being "incompressible" must leave the generation site; this can be facilitated through pressure build up caused by the roughly 50% excess volume which leads to localized hydraulic fracturing.
Evaluation of Well Performance for the Slot-Drill Completion in Low and Ultra-Low Permeability Oil and Gas Reservoirs
Authors: Odunowo T. O. , Moridis G. J. , Blasingame T. A. , Olorode O. M. , Freeman C. M. 
Published: April 2013

Abstract
Low to ultralow permeability formations require "special" treatments/stimulation to make them produce economical quantities of hydrocarbon and at the moment, multi-stage hydraulic fracturing (MSHF or MHF) is the most commonly used stimulation method for enhancing the exploitation of these reservoirs. Recently, the slot-drill (SD) completion technique was proposed as an alternative treatment method in such formations (Carter 2009).
This paper documents the results of a comprehensive numerical simulation study conducted to evaluate the production performance of the SD technique and compare its performance to that of the standard MSHF approach. We investigated three low permeability formations of interest, namely a shale-gas, a tight-gas, and a tight/shale-oil formation. The simulation domains were discretized by using Voronoi gridding schemes to create representative meshes of the different reservoir and completion systems modeled in this study.
The results from this study indicated that the SD method does not, in general, appear to be competitive in terms of reservoir performance and recovery compared to the more traditional MSHF method. Our findings indicate that the larger surface area to flow that results from the application of MSHF is much more significant than the higher conductivity achieved using the SD technique. However, there may exist cases, e.g., lack of adequate water volumes for hydraulic fracturing, or very high irreducible water saturation that leads to adverse relative permeability conditions and production performance, in which the low-cost SD method may make production feasible from an otherwise challenging (if not inaccessible) resource.
Stochastic Modeling of Two-Phase Flowback of Multi-Fractured Horizontal Wells to Estimate Hydraulic Fracture Properties and Forecast Production
Authors: Williams-Kovacs J. D. , Clarkson C. R. 
Published: April 2013

Abstract
Although high-frequency fluid production and flowing pressures (hourly or greater) are commonly gathered in multi-fractured horizontal wells (MFHW), this data has rarely been used by industry in a quantitative manner to characterize hydraulic fracture or reservoir parameters and there has been ongoing debate about the usefulness of this data. It is likely that the multi-phase flow nature and the possibility of early data being dominated by wellbore storage have deterred many analysts.
This work will expand on the flowback analysis work presented by Clarkson (2012b). Consistent with that work, our interpretation is that the early flowback data corresponds to wellbore + fracture volume depletion (storage) and it is assumed that fracture storage volume is much greater than wellbore storage. From this flow-regime, bulk permeability (dominated by fracture permeability) and effective fracture half-length can be estimated. However, as pointed out by Clarkson (2012b) there is a large degree of uncertainty in this type of analysis as a result of the number of unknowns which are being adjusted to provide an adequate history match. To better understand the uncertainty and the impact of each parameter, stochastic simulation was used to provide a range of parameter values, which provide an adequate fit of the data, and to determine which parameters have the greatest impact on the match. Stochastic simulation is also used to derive a long-term forecast using parameters derived from flowback analysis. Additional improvements over previous work include the consideration of different fracture geometries, the use of the matchstick model to estimate fracture permeability and additional constraints on relative permeability curve selection. The field cases presented by Clarkson (2012b) for shale gas reservoirs are reanalyzed for proof of concept and demonstration of the developed techniques.
Effect of Reservoir Heterogeneity on Improved Shale Oil Recovery by CO2 Huff-n-Puff
Authors: Chen Cheng , Balhoff Matthew , Mohanty Kishore K. 
Published: April 2013

Abstract
An equation-of-state based compositional reservoir simulator, UT-COMP, is used to simulate the improved oil recovery by CO2 huff-n-puff in a shale matrix typical of the Bakken Formation. Non-aqueous components are carefully lumped into seven pseudo components. Permeability fields with various heterogeneity and correlation lengths are generated. UT-COMP is able to solve the compositional model, despite the permeability difference between the fracture and matrix being six orders of magnitude. Multiple cycles of CO2 huff-n-puff are simulated and compared with production by primary depressurization. The oil is first contact miscible with the injected CO2 under the reservoir pressure. Simulations show that primary recovery outperforms CO2 huff-n-puff in an ideally homogenous reservoir because injected CO2 moves deep into the reservoir without much increase in near-well pressure, while CO2 huff-n-puff outperforms primary recovery if there exists a low-permeability region which keeps CO2 in the near-well bore injection region. In the latter case, the final recovery using CO2 huff-n-puff is higher than that from primary depressurization; the recovery in a single cycle is about 3.3%, which increases to 3.5% in about 3 cycles. The recovery factor after 1000 days by primary depressurization with production pressure of 1000 psi is 11.6%, which is in agreement with existing studies. The recovery increase can be fit by a two-parameter exponential function and the rate coefficient is found to be insensitive to correlation length, while depends mainly on reservoir heterogeneity. A linear relationship between heterogeneity and rate coefficient is obtained. This work is the first to investigate the effect of heterogeneity on improved hydrocarbon recovery by CO2 huff-n-puff, and will be valuable in understanding the coupling between shale properties and oil recovery.
Does Mandatory IFRS Adoption Affect the Credit Ratings of Foreign Firms Cross-Listed in the U.S.?
Authors: Chan Ann Ling-Ching , Hsu Audrey Wen-hsin , Lee Edward 
Published: April 2013

SYNOPSIS:
We examine whether the mandatory adoption of International Financial Reporting Standards (IFRS) affects the credit ratings of foreign firms cross-listed in the U.S. Consistent with the influence of accounting information quality on credit ratings that is established in the literature, we find significantly higher credit ratings among these cross-listed firms after IFRS. Furthermore, this effect is more pronounced among those from countries where there is a greater difference between previous domestic standards and IFRS, and from countries that had weaker legal enforcement and investor protection before the transition. Our findings are consistent with IFRS improving the transparency and creditworthiness of foreign firms cross-listed in the U.S. by reducing their information costs and risk for U.S. investors. The evidence implies that IFRS adoption in their home country could benefit firms that are already cross-listed or are seeking to cross-list in the U.S.
JEL Classifications: F30; G15; M41.