bluuebunny/crossref_metadata_2025 huggingface dataset:
Probiotic Administration in Early Life, Atopy, and Asthma: A Meta-analysis of Clinical Trials
Authors: Elazab Nancy , Mendy Angelico , Gasana Janvier , Vieira Edgar R. , Quizon Annabelle , Forno Erick
Published: August 2013

BACKGROUND AND OBJECTIVE:

Probiotics may reduce the risk of atopy and asthma in children. However, results from clinical trials have been conflicting, and several of them may have been underpowered. We performed a meta-analysis of randomized, placebo-controlled trials to assess the effects of probiotic supplementation on atopic sensitization and asthma/wheeze prevention in children.

METHODS:

Random-effects models were used to calculate pooled risk estimates. Meta-regression was conducted to examine the effect of potential factors on probiotics efficacy.

RESULTS:

Probiotics were effective in reducing total immunoglobulin E (IgE) (mean reduction: –7.59 U/mL [95% confidence interval (CI): –14.96 to –0.22]; P = .044). Meta-regression showed that the reduction in IgE was more pronounced with longer follow-up. Probiotics significantly reduced the risk of atopic sensitization when administered prenatally (relative risk: 0.88 [95% CI: 0.78 to 0.99]; P = .035 for positive result on the skin prick test and/or elevated specific IgE to common allergens) and postnatally (relative risk: 0.86 [95% CI: 0.75 to 0.98]; P = .027 for positive result on skin prick test). Administration of Lactobacillus acidophilus, compared with other strains, was associated with an increased risk of atopic sensitization (P = .002). Probiotics did not significantly reduce asthma/wheeze (relative risk: 0.96 [95% CI: 0.85 to 1.07]).

CONCLUSIONS:

Prenatal and/or early-life probiotic administration reduces the risk of atopic sensitization and decreases the total IgE level in children but may not reduce the risk of asthma/wheeze. Follow-up duration and strain significantly modified these effects. Future trials for asthma prevention should carefully select probiotic strain and consider longer follow-up.
A Young Adult Jehovah’s Witness With Severe Anemia
Authors: Ukachi Nnenna , Morrison Wynne , VanHorn Samantha , Sundaram Revathy , Lantos John D.
Published: August 2013

Two of the most ethically complex situations in pediatrics are those involving families whose religious beliefs preclude the provision of life-sustaining treatment and those involving young adults who have reached the age of legal majority and who face decisions about life-sustaining treatment. This month’s “Ethics Rounds” presents a case in which these 2 complexities overlapped. An 18-year-old Jehovah’s Witness with sickle cell disease has life-threatening anemia. She is going into heart failure. Her doctors urgently recommend blood transfusions. The young woman and her family adamantly refuse. Should the doctors let her die? Is there any alternative?
Use of a Computerized Decision Aid for ADHD Diagnosis: A Randomized Controlled Trial
Authors: Carroll Aaron E. , Bauer Nerissa S. , Dugan Tamara M. , Anand Vibha , Saha Chandan , Downs Stephen M.
Published: August 2013

OBJECTIVE:

To determine if implementing attention-deficit/hyperactivity disorder (ADHD) diagnosis and treatment guidelines in a clinical decision support system would result in better care, including higher rates of adherence to clinical care guidelines.

METHODS:

We conducted a cluster randomized controlled trial in which we compared diagnosis and management of ADHD in 6- to 12-year-olds after implementation of a computer decision support system in 4 practices.

RESULTS:

Eighty-four charts were reviewed. In the control group, the use of structured diagnostic assessments dropped from 50% in the baseline period to 38% in the intervention period. In the intervention group, however, it rose from 60% to 81%. This difference was statistically significant, even after controlling for age, gender, and race (odds ratio of structured diagnostic assessment in intervention group versus control group = 8.0, 95% confidence interval 1.6–40.6). Significant differences were also seen in the number of ADHD core symptoms noted at the time of diagnosis. Our study was not powered to detect changes in care and management, but the percent of patients who had documented medication adjustments, mental health referrals, and visits to mental health specialists were higher in the intervention group than the control.

CONCLUSIONS:

The introduction of a clinical decision support module resulted in higher quality of care with respect to ADHD diagnosis including a prospect for higher quality of ADHD management in children. Future work will examine how to further develop the ADHD module and add support for other chronic conditions.
Lehman Syndrome: A New Syndrome for Pierre Robin Sequence
Authors: Correia-Sá Inês , Horta Ricardo , Neto Tiago , Amarante José , Marques Marisa
Published: August 2013

Lehman syndrome, or lateral meningocele syndrome, is characterized by facial dysmorphism, multiple lateral meningoceles, and skeletal abnormalities. Only nine cases have been described. We present a case of a 2-year-old boy presenting with micrognathia, glossoptosis, and hypertelorism as well as associated severe obstructive sleep apnea. He was submitted to bilateral mandibular distraction with external nonresorbable devices to correct Pierre Robin sequence (PRS). Later, multiple lateral meningoceles were identified, and a diagnosis of Lehman syndrome was made. Lehman syndrome must be considered in syndromic infants with PRS. Distraction osteogenesis is a safe procedure that is effective as a first choice in the treatment of patients with Lehman syndrome presenting with micrognathia.
β-Catenin Mutation Status and Outcomes in Sporadic Desmoid Tumors
Authors: Mullen John T. , DeLaney Thomas F. , Rosenberg Andrew E. , Le Long , Iafrate A. John , Kobayashi Wendy , Szymonifka Jackie , Yeap Beow Y. , Chen Yen-Lin , Harmon David C. , Choy Edwin , Yoon Sam S. , Raskin Kevin A. , Hornicek Francis J. , Nielsen Gunnlauger P.
Published: August 2013

Learning Objectives

Describe the frequency of CTNNB1 mutations in sporadic desmoid tumors. Summarize findings regarding CTNNB1 mutation status and disease outcome.
Proximity to agriculture alters abundance and community composition of wild sunflower mutualists and antagonists
Authors: Chamberlain Scott A. , Whitney Kenneth D. , Rudgers Jennifer A.
Published: August 2013

Anthropogenic modifications of the landscape, such as agriculture, are widespread globally and can reduce native biodiversity and homogenize communities by decreasing variation in species composition across sites. Partitioning anthropogenic impacts among species that have positive versus negative effects on plants may improve our ability to forecast the ecological and evolutionary consequences of these alterations in communities. Here, we manipulated the distance of populations of a wild sunflower species (Helianthus annuus texanus) to fields of its domesticated relative (crop sunflowers, H. annuus) and contrasted subsequent shifts in the abundance and community composition of mutualists (pollinators) and antagonists (seed predators, folivores) of H. a. texanus. With some exceptions, populations of H. a. texanus near crop sunflowers supported higher numbers of pollinators than those far from crop sunflowers. In contrast, in the majority of cases, populations of H. a. texanus supported more seed predators when located far from crop sunflowers. Folivore damage to plants was greater far from crop sunflowers, and was never greater near crop sunflowers. Contrary to the prediction that proximity to agriculture homogenizes community composition, we found β‐diversity of pollinators (species turnover between populations) was greater near crop sunflowers. Our results demonstrate that mutualists and antagonists of a wild plant species respond differently to the proximity of a related crop species, indicating the potential for both altered population dynamics and complex selection pressures on wild species in agricultural landscapes.
Disassembly of a dune‐dwelling lizard community due to landscape fragmentation
Authors: Leavitt Daniel J. , Fitzgerald Lee A.
Published: August 2013

Landscape fragmentation alters patterns of landscape structure that affect quality and configuration of habitats, and disrupts population dynamics and persistence of species. Community disassembly, a process of community change due to nonrandom species losses and declines, is occurring worldwide as a result of landscape fragmentation, habitat loss, and habitat degradation. We carried out a comparative study at 27 trapping sites designed to characterize how fragmentation affects community structure in a dune‐dwelling lizard community. Lizard communities in non‐fragmented sites demonstrated nested community structure. Conversely, lizard communities at sites fragmented by roads and well pads from oil and gas development had consistently lower abundance of two species, and demonstrated random community structure. Species loss and lower abundance of species at fragmented sites suggested a pattern of community disassembly. The dunes sagebrush lizard (Sceloporus arenicolus), an ecological specialist, and the lesser earless lizard (Holbrookia maculata) were present on most non‐fragmented sites. However, neither species was present on more than half of the fragmented sites, and their abundances were much lower than on non‐fragmented sites. We attributed reduced species diversity on fragmented sites to quantitative differences in landscape configuration compared to non‐fragmented sites. Specifically, both size and shape of sand dune blowouts differed between non‐fragmented and fragmented sites. Fragmented sites possess more large patches of open sand and barren ground and fewer, smaller, and more dispersed shinnery dune blowouts. Patterns of occurrence and relative abundance suggest S. arenicolus and H. maculata were sensitive to these patch‐scale attributes. In this ecosystem, landscape‐scale fragmentation appears to influence landscape configuration and community disassembly at the patch‐scale. Our findings allow us to disentangle drivers of species loss and enhance our understanding of the processes of community disassembly in fragmented landscapes.
Bringing the Kok effect to light: A review on the integration of daytime respiration and net ecosystem exchange
Authors: Heskel Mary A. , Atkin Owen K. , Turnbull Matthew H. , Griffin Kevin L.
Published: August 2013

Net ecosystem exchange (NEE) represents the difference between carbon assimilated through photosynthesis, or gross primary productivity (GPP), and carbon released via ecosystem respiration (ER). NEE, measured via eddy covariance and chamber techniques, must be partitioned into these fluxes to accurately describe and understand the carbon dynamics of an ecosystem. GPP and daytime ER may be significantly overestimated if the light inhibition of foliar mitochondrial respiration, or “Kok effect,” is not accurately estimated and further integrated into ecosystem measurements. The light inhibition of respiration, a composite effect of multiple cellular pathways, is reported to cause between 25‐100% inhibition of foliar mitochondrial respiration, and for this reason needs to be considered when estimating larger carbon fluxes. Partitioning of respiration between autotrophic and heterotrophic respiration, and applying these scaled respiratory fluxes to the ecosystem‐level proves to be difficult, and the integration of light inhibition into single and continuous measures of ecosystem respiration will require new interpretations and analysis of carbon exchange in terrestrial ecosystems.
Laboratory Measurement of Sorption Isotherm Under Confining Stress With Pore-Volume Effects
Authors: Santos J.M.. M. , Akkutlu I.Y.. Y.
Published: August 2013

For unconventional gas resources such as coal and organic-rich shale, sorbed phase is an important component of storage and transport calculations. Routine measurements of sorption are, however, performed separately from the porosity and permeability measurements. In this work, a new gas-storage measurement technique is proposed that combines the porosity and sorption measurements. Because the measurement is performed by use of core plugs under confining stress, it allows investigating the storage capacity for varying effective stress and incorporating the storage data into a subsequent permeability measurement under the same conditions.

During the construction of the sorption isotherm in the laboratory with the volumetric (gas expansion) method, at each pressure step, the sorbed gas taken up by the sample reduces the pore volume (PV) of the sample. As a result, the initially determined PV at low pressure must be corrected at the beginning and at the end of the pressure step. This correction can be performed relatively easily during the routine sorption measurements with the crushed samples; however, it is a challenging task with core plugs under confining stress because at each pressure step the PV could also change as a result of pore compressibility. Our approach is based on a new analytical model of total gas storability developed to interpret the measured multiple-step pressure data on a graphical domain in which the storage-parameter estimation can be performed fast and accurately with a straight line. The approach considers both the compressibility and the sorbed-phase effects on the porosity and the sorption parameters.

Experimental storage data of shale and coal samples with varying total organic content (TOC) and maturity are used to demonstrate the applicability of the analytical method to the measurements. The results show that the sorption measurements can be performed with increased accuracy and relatively fast. The work is important for organic-rich sample characterization in the laboratory, and for gas-in-place and transport calculations.
Quantifying the Effect of Drilling Azimuth in Shale Gas Reservoirs
Authors: Wutherich Kevin , Xu Lili , Walker Kirby , Sawyer Walter , Reese Stephen , Aso Isaac
Published: August 2013

With the advent of horizontal drilling and fracturing low-permeability reservoirs to produce hydrocarbons, it has become common practice within most fields to drill wells in the direction of minimum horizontal stress in a normal stress region to maximize production and minimize drilling risk. The primary reason for this is that induced fractures tend to propagate along the plane containing the intermediate and maximum stresses (typically overburden and maximum horizontal stresses in a normally stressed region), which, under these conditions, is perpendicular to the horizontal wellbore. This allows for maximum extension away from the wellbore into the reservoir allowing for maximum reservoir contact by the induced fractures. This has been consistently demonstrated to provide the maximum coverage.

However, it is sometimes the case that wells are drilled at an azimuth that is not in line with the minimum stress. This might be due to such things as irregular lease boundaries or perhaps even variations in localized stress regimes that cause the stress direction to shift from the expected regional stress directions. These changes in a drilled well's azimuth with respect to minimum in-situ stress can have a significant effect on stimulation effectiveness and, eventually, the estimated ultimate recovery (EUR) of the wells.

A study of off-azimuth drilling addressed issues of how to determine minimum stress direction, the effect of such drilling on wellbore stability and the safe mud-weight window, how the completion design might be affected, and how to estimate the expected changes in productivity. Theoretical and empirical data were used to quantify these effects; data used included wireline logs, publicly available production data, microseismic data, and computer simulations, with a particular emphasis on the Marcellus shale.
What can we Learn from Existing Completions? : A Shale Gas Case Study
Authors: Jayakumar R. , Yalavarthi R. , Nyaabba C. , Rai R.
Published: August 2013

In recent years, a demand for clean burning fossil fuel and advancements in horizontal drilling has resulted in an increase in shale activity around the world. Due to extremely low shale matrix permeability, shale resources require successful hydraulic fracturing for the economic viability of a well. Operators have experimented with various completion methodologies to determine their potential, hoping to find the best completion practice for their shale play. A recent decline in natural gas prices have reduced the leverage needed for extensive experimentation. As a result, understanding the existing completion design has become critical.

In this paper, we compared multiple pairs of wells drilled in close proximity but have varying performance in each pair. The reservoir properties are based on the petrophysical analysis of the offset pilot well. As the wells in the pair share same petrophysical properties, the difference in performance should be related to changes in completion characteristics. This paper demonstrates workflow for determining completion characteristics by calibrating well performance to the fracture characteristics. A hydraulic fracture model incorporating rock geo-mechanical properties and actual fracture treatment data provides the estimate of hydraulic and propped fracture dimensions and properties. The results show how the changes in completion impact fracturing behavior can be correlated to observed well performance. The approach leverages current completion data weather successful or unsuccessful to build a knowledgebase which can guide us towards optimal future completion strategies sooner by reducing the amount of trial and error required.
A Systematic Study for Refracturing Modeling Under Different Scenarios in Shale Reservoirs
Authors: Jayakumar R. , Rai R. , Boulis A. , Araque-Martinez Aura
Published: August 2013

A key characteristic in unconventional reservoirs development is that they need massive hydraulic fracturing to create high permeability conduits to connect the reservoir to the wellbore and assure appropriate flow rates to make the development economical. In general, production performance for this type of reservoirs show an early high inflow followed by a steep decline. Refracture jobs have been a common practice to mitigate the flow rate decline and revitalize wells productivity.

In this paper, a wide range of possible refrac configurations are evaluated using synthetic models. Parameters such as fracture spacing, matrix permeability, fracture conductivity, fracture orientation and refrac locations were varied to study their impact on the success of the refrac job. Results showed significant impact on both the overall productivity, recovery and the economic value. The results show the impact of refracturing in higher permeability cases (greater than micro Darcy) is not as economical as in the low permeability scenarios (less than micro Darcy). Results also show a possible threshold in fracture spacing (60 – 80 ft between clusters) below which refracturing may not an economical completion strategy. In scenarios where the initial fracture conductivity is severely degraded, refrac can be an alternative to improve the net present value (NPV) and estimated ultimate recovery (EUR). Under the conditions of this study, fracture re-orientation cases show improvement in recovery factor (RF) but does not have a significant impact on the overall NPV. The timing of refrac has a large impact on both the NPV and recovery for the wells. In all cases, NPV was used to define optimal condition for each scenario evaluated.

All cases presented demonstrate potential impact of refracturing for a typical range of properties in shale reservoirs. The results shown in the paper could be used as a catalogue for better decision support to estimate the impact of refracturing in field cases under similar configurations to determine whether refrac will beneficial.
Evaluation of Quintuple Porosity in Shale Petroleum Reservoirs
Authors: Lopez Bruno , Aguilera Roberto
Published: August 2013

The use of a quintuple porosity system for calculation of original petroleum in place (OPIP) in shales is important as neglecting some of the porosities can result in pessimistic values of OPIP and production rates. Based on the concept of Total Petroleum System (Magoon and Beaumont, 1999) the word ‘Petroleum’ includes (1) thermal and biological hydrocarbon gas, (2) condensates, (3) crude oils and (4) natural bitumen. In the case of natural gas, the gas is trapped and stored in shale in different ways: (1) gas adsorbed in the kerogen material, (2) free gas trapped in nonorganic inter-particle (matrix) porosity, (3) free gas trapped in microfracture and slot porosity, (4) free gas stored in hydraulic fractures created during the stimulation of the shale reservoir, and (5) free gas trapped in a pore network developed within the organic matter or kerogen. An additional storage element is provided by gas dissolved in kerogen.

The governing equations that describe the gas mass balance in the quintuple porosity model are presented in detail. The series and parallel gas transport approaches discussed previously in the literature are shown to be special cases of the new general gas transport formulation developed in this study. The effects of permeability stress-dependency are taken into account. Real data from Devonian gas shales are used to illustrate the effect of free gas, adsorbed gas and dissolved gas in a material balance crossplot of P/Z vs. cumulative gas production.

Historically, the large contribution of organic porosity, natural fractures and hydraulic fractures that can contribute a significant amount of free petroleum in place has not been taken into account. And many of the laboratory experiments used for determining data utilized in computations of OPIP and production rates have been carried out in crushed samples, which by their very nature do not generally preserve natural fractures, slots and all the porosity present in the organic matter. This leads to pessimistic values of OPIP and rates. This helps to explain the larger than anticipated rates and recoveries of natural gas from some of these formations, for example Devonian shales, which have been producing for several decades.

Although the quintuple porosity characterization mentioned above indicates very heterogeneous systems, the production performance is less heterogeneous than that of carbonates, sandstones and naturally fractured tight reservoirs. This surprising result is demonstrated with the use of actual production data from various petroleum reservoirs around the world. The subject matter is significant because of the large volume of petroleum resources in shales throughout the world, which probably are underestimated because of not considering in a single model all types of porosity discussed in this study.
Geomechanical Reservoir Characterization with Microseismic Data
Authors: Tarrahi Mohammadali , Jafarpour Behnam , Ghassemi Ahmad
Published: August 2013

Bulk fluid injection into low permeability geologic formations been observed to trigger microearthquakes (MEQs). Triggering of MEQ events has been linked to pore pressure, temperature, and in-situ stress variations. The resulting clouds of micro-seismic events are believed to carry information about the underlying coupled flow, geomechanics, and thermal processes and, hence, rock hydraulic and mechanical properties. We develop a framework for integrating injection-induced microseismic events as monitoring data to infer reservoir property distributions. To model the reservoir stimulation and induced microseismicity, we use a fully coupled thermo-poroelastic model with coupled heat transport, fluid flow, and rock deformation capabilities as forward model and apply the ensemble Kalman filter (EnKF) data assimilation algorithm invert MEQ measurements. Because discrete MEQ events are not amenable to continuous estimation methods, we first use a kernel density estimation (KDE) method to convert the observed cloud of MEQ events into a continuous seismicity density map. We then apply a variant of the EnKF to integrate the resulting continuous seismicity density map to estimate, individually and jointly, heterogeneous hydraulic and geomechanical rock property distributions such as permeability, Young's modulus, tensile strength and Cohesion. We apply a spectral projection approach to decorrelate the spatially correlated observation of MEQ for improved EnKF implementation. We use numerical experiments to evaluate the performance of the developed methods.
Effect of Low-Concentration HCl on the Mineralogical, Mechanical, and Physical Properties of Shale Rocks
Authors: Morsy Samiha , Hetherington C. J. , Sheng J. J.
Published: August 2013

Oil and gas-bearing shale formations have received a great deal of interest in recent years, especially in North America. Oil and gas from shale could make a significant contribution to global hydrocarbon production. However, their development has been hindered by the complexity of drilling and completion strategies, which must be adapted in response to shale's mineralogy and physical properties. Matrix acidizing is commonly used as a pre-flush to the hydraulic fracturing stimulation of shale formations. The process dissolves sediments and mud solids that inhibit the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons. In some plays it is used as the main stimulation technique (e.g. Monterey shale, California). In this paper, the mineralogical and physical responses to matrix acidizing of several important North American shale formations were evaluated, and the effects on their physical properties are described. Samples of Eagle Ford, Mancos, Barnett and Marcellus shale formations were exposed to different concentrations of HCl (1-3 wt%). Based on experimental observations, mass loss, and X-ray diffraction studies, the samples lost as much as 16 wt. % calcite when treated with 3 wt% of HCl for three hours. Post-reaction measurements show increases in porosity in all experiments, which was attributed to calcite dissolution in Eagle Ford samples and to crack development in Mancos, Barnett, and Marcellus samples. Eagle Ford samples showed the greatest reduction in Young's Modulus ranging from 25-82% when exposed to 1-3 wt% HCl solutions and 75% when exposed to 5 wt% NaCl saline solution at 200°F.
Generalized Inflow Performance Relationship (IPR) for Horizontal Wells
Authors: Mohammadnia Mohammadreza , Akbari Babak , Shahri Mojtaba P. , Shi Zhaorui , Zhang Holden
Published: August 2013

The horizontal well technology can solve different problems of production from tight formations where conventional technology fails. The aim of this study is to develop a generalized IPR for an oil reservoir in which a well is drilled horizontally. A reservoir simulator is used to simulate the production through this well to construct the IPR curves. A simulation matrix is designed by changing well geometry, well position and rock properties. The IPR data obtained from the numerical simulations are fitted to a Vogel-type relationship and the values of the coefficient, b, are calculated corresponding to different conditions. Consequently, a statistical analysis method is used to determine which factors in the simulation matrix have a significant effect on the value of b. The results show that the only significant factor is the vertical to horizontal permeability ratio of the reservoir. Using the Vogel-type IPR and the correlation for b obtained from statistical analysis in terms of the vertical to horizontal permeability ratio, an IPR suitable for horizontal well productivity is developed taking into account the reservoir and well parameters. In this relationship, the factor b is a function of the vertical to horizontal permeability ratio. The new model is tested against random simulations that are not included in the original simulation matrix for the model development, and better agreement is observed compared to the predictions of previous IPR's available in the literature.
Coupling Mechanical Changes of a Fracture to Hydraulic Changes
Authors: Crandall Dustin , Gill Magdalena , McIntyre Dustin L , Bromhal Grant S
Published: August 2013

Flow within fractured shale is a topic of interest for both production from non-traditional fractured shale reservoirs and for estimating the leakage potential through sealing formations above geologic carbon dioxide repositories. The hydraulic aperture of a fracture describes how much fluid can be transported though a fracture; this is similar to permeability through porous media. The advantage of determining a hydraulic aperture as opposed to fracture permeability is that this fracture fluid transport property can be scaled up to discrete fracture reservoir simulators, such as NFFLOW. Unfortunately, many parameters can affect the hydraulic aperture of an individual fracture, including the roughness of the fracture surfaces, the average mechanical aperture of the fracture, and the tortuosity of the flow path within the fracture volume. For this study, we examine the relationship between the mechanical aperture of individual fractures and the hydraulic aperture of that fracture.

Within the computed tomography/core flow facility at the National Energy Technology Laboratory we have examined changes in hydraulic aperture of individual fractures with changes in the confining stresses that externally act upon the fractured samples. Tests were conducted with locally sourced shaly limestone from a depth of approximately 200 ft. Initial and numerical results show that the volume change in the fracture is a non-linear function of the confining pressure, and that this mechanical change reduces the individual fracture permeability rapidly as the fracture is first compressed.
Optimizing Surfactant Additives for Low-Permeability Wet Gas Formations: A Laboratory Approach for Correlating Capillary Pressure and Emulsion Tendency with Surfactant Performance
Authors: Xu Liang
Published: August 2013

For low-permeability gas reservoirs, surfactants are typically added into fracturing cocktails to lower the capillary pressure in the pore spaces to enable a faster return of fracturing water to the surface, thereby providing additional surface area for gas flow. Capillary pressure inside pore spaces, however, is not straightforward to predict or correlated to the performance of the surfactant that is to be used during fracturing. In this paper, a laboratory approach is presented for comparing surfactant performance by using the Washburn method for surfactant imbibition in crushed core particles from various unconventional formations, such as the Marcellus formation. Through analysis of the initial slopes of the imbibition curves over time at different salinities, it is possible to predict which surfactant would more effectively lower capillary pressure. In addition, gas production is often accompanied by condensate, which can accumulate in the near-wellbore (NWB) region, causing poor inflow performance. To overcome this issue, a transient or short-lived condensate-in-water emulsion is likely required to mobilize condensate more efficiently. Performing emulsion tendency analysis assisted with visual inspection demonstrated that weakly emulsifying surfactants are likely a better choice than typical field standard non-emulsifying surfactants.

Production data from the Barnett formation are presented to validate the performance of the surfactant selected from imbibition and emulsion tendency analysis.
Modeling Guidelines for Analyzing and Forecasting Shale Well Performance
Authors: Kanfar M. S. , Alkouh A. B. , Wattenbarger R. A.
Published: August 2013

There are many mathematical models for production data analysis of shale wells. Certain models assume a set of parallel hydraulic fractures perpendicular to a horizontal well. Some of these models include natural fractures perpendicular to the hydraulic fractures. In these models, there is uncertainty in whether transient linear flow is dominated by fractures or matrix. Identification of the medium in transient flow usually requires assuming fracture properties. In this paper, we introduce an identification method which does not require explicit knowledge of fracture properties. This work also helps forecast wells which have not reached boundary dominated flow decline.

The paper focuses on four fracture distribution models that could describe shale wells. We introduce the identification procedure to determine the true fracture distribution model for a region. Once the model is identified, it is possible to determine whether linear flow is dominated by matrix or fractures. Identification of the true model can also improve forecast accuracy. The model identification procedure is based on the assumption that rock and fluid properties are similar within the region of interest.

Shale wells often exhibit long transient linear flow. Forecast projection is uncertain because the end of linear flow cannot be calculated without knowledge of fracture properties. The model identification procedure presented here enables more accurate production forecast and analysis. In addition, model identification might help optimize fracture design for future wells. This work reduces uncertainty and eliminates inapplicable models.
New Technology Enables Rigs With Limited Pump Pressure Capacity to Utilize the Latest Friction Reduction Technology
Authors: Burnett Timm , Gee Ryan , Martinez Jose , Carson Christopher , Canuel Léo
Published: August 2013

This paper presents a case study of the successful use of existing friction reduction technology coupled with advanced tool designs to allow optimization of the friction reduction system for the application.

Friction reduction in vertical, directional and horizontal wells can be critical to enable the transfer of weight to the drill bit. Excessive friction can limit the driller's ability to maintain tool face and to get weight to the bit, thus limiting the depth and accuracy of the well. There are various tools currently on the market that help mitigate friction in different ways; the most commonly used tool is the Drilling Agitator System (DAS).

A limitation for these tools in some cases is the amount of pressure drop these tools create, which increases the stand pipe pressure while drilling. This can be a limitation for contractors and operators who are already reaching the limits of their pump pressure capacity with their current drilling BHAs. This limitation prevents a segment of the drilling market from the ability to use these friction reduction tools. Additionally, as the need to drill farther horizontally to retrieve natural resources increases, the need for a low pressure friction reduction tool that can effectively break friction while adding a smaller amount of pressure to the drilling system is more desireable.

This paper focuses on the development of an advanced tool design capable of reducing the amount of pressure added to the stand pipe by the Drilling Agitator System (DAS). A discussion of the design of the tools, case histories and field trial results will be presented.
Key Parameters Affecting Successful Hydraulic Fracture Design and Optimized Production in Unconventional Wells
Authors: Meyer Bruce R. , Bazan Lucas W. , Brown Eric K. , Brinzer Bill C.
Published: August 2013

Multi-stage/multi-cluster hydraulic fracturing in horizontal wellbores is a key technology driving the development of unconventional resources in North America. It has been observed that complex fracture behavior can result from hydraulic fracture stimulation in these unconventional horizontal wells. Given the rapid pace of development, many operators strive to standardize their completion program to drive consistency, and efficiency, in operations and well performance. Unfortunately, the hydraulic fracture treatments may not be properly designed to maximize well deliverability, but instead focus on maximizing contacted reservoir volume (CRV). Generating fracture complexity is important in unconventional reservoirs, but maximum reservoir contact does not necessarily translate to an effectively stimulated reservoir with conductive fracture paths back to the wellbore.

Hydraulic fracture modeling in resource plays is challenging and often reduced to rules of thumb and design concepts taken from other shale plays. Key parameters that should be considered to maximize production in unconventional reservoirs are not dissimilar to the key parameters proven successful time and again in conventional completion designs and fracturing treatments.

The need for improved proppant pack permeability and fracture conductivity in unconventional wells has been well documented. However, there are additional completion and design considerations for unconventional wells such as natural fracture saturation, mid-field fracture complexity (MFFC), mechanical fracture interaction and transverse fracture production interference.

This paper summarizes a number of important considerations and key parameters that are necessary to design successful hydraulic fracture treatments and enhance productivity in unconventional wells. Application and considerations of these parameters will help provide the operator with a systematic, engineering based design method for optimizing multistage/multi-cluster hydraulic fracture treatments in horizontal wellbores.
Analytical Solution of Transient Multiphase Flow to a Horizontal Well With Multiple Hydraulic Fractures
Authors: Shojaei Hasan , Tajer Ehsan S.
Published: August 2013

This paper presents an analytical model for three-phase flow towards a horizontal well with multi-stage hydraulic fractures, producing from a low-permeability oil reservoir (e.g. shale oil) under primary depletion. The model accounts for time-dependent trilinear-flow model (Brown et al. 2011) and solution-gas drive model (Muskat 1981).

While there are numerous analytical models proposed for inflow of horizontal wells with multistage fractures, they do not consider three-phase flow condition and/or time dependent behavior (i.e. they assume steady or pseudo-steady state conditions). These two conditions should be honored for low-permeability oil reservoirs with prolonged transient period which produce oil, water and dissolved gas.

In this paper, we first present the mathematical framework for the transient three-phase trilinear flow towards a multi-fractured horizontal well in a bounded oil reservoir. Later, we combine the flow equations with the material balance equations to account for pressure depletion and solution-gas drive during primary production. We compare the predictions of our analytical model with a commercial numerical simulator. We demonstrate very good agreements of these two different approaches. Last, the advantages and limitations of this new method are discussed.

Production forecast using the presented analytical model is significantly faster in comparison to the numerical simulator. This finds applications where multiple realizations are required, either during the optimal design of key factors (i.e. number of stages, spacing, optimal fracture conductivity) or during the characterization of hydraulic fractures by matching the production history.
Probabilistic Evaluation of Global Technically Recoverable Tight Gas Resources
Authors: Dong Zhenzhen , Holditch Steve A. , Ayers Walter B.
Published: August 2013

For many countries outside North America, potentially large resources of natural gas in place are present in unconventional reservoirs, such as tight (low-permeability) sandstone/limestone, shales and coal beds. However, there are no reliable estimates of technically recoverable resources (TRR) for these unconventional reservoirs, and many countries lack advanced technology, such as horizontal drilling and hydraulic fracturing, necessary to develop unconventional resources. To encourage investment in these technologies, new resources estimates are needed. The objective of this study was to develop a methodology and software for probabilistic resource estimation, and to use this new technology to estimate global technically recoverable gas resources in tight sands.

Tight gas reservoirs are present in every petroleum province, and global tight gas resources in place are large. However, it is uncertain how much of the in-place resource is technically recoverable. Although some publications report TRR of tight gas for small geographical areas, little is known publicly about these resources on a global scale.

The objective of our work was to determine the probabilistic distribution of TRR of tight gas, worldwide. To achieve this goal, we developed a computer program, Unconventional Gas Resource Assessment System (UGRAS). The program integrates a Monte Carlo technique with an analytical reservoir simulator. This combination provides an excellent means to predict production profiles for a wide variety of reservoir characteristics and producing conditions. Using UGRAS, we established probabilistic distributions of original gas in-place and TRR for selected tight gas formations in the United States and derived a representative distribution of recovery factors for tight gas reservoirs. The recovery factors follow a logistic distribution, with a P50 of 79%.

We extended the distribution of recovery factors gained from our analyses of tight gas reservoirs in the United States to estimate TRR of tight gas worldwide, outside the United States. Global technically recoverable tight gas is estimated to be 38,000 (P10) to 84,000 (P90) Tcf, with a P50 value of 58,000 Tcf. Results of this work support the existence of significant global resources of technically recoverable tight gas and may have potential to guide energy strategy, such as to forecast future energy supply worldwide. UGRAS is a robust tool that may be used to evaluate and rank tight gas resources, worldwide.
Impact of Delays and Shut-Ins on Well Productivity
Authors: Crafton James W. , Noe Sandra L.
Published: August 2013

A population of over 270 wells, including over 80 Marcellus wells, was investigated to assess the impact of various early production management strategies, with attention given to the time delay between stimulation and first production, often referred to as the "resting" or "soak" period and the effect of subsequent shut-ins. Subsets of this population were used to perform the various evaluations. Four significant control factors became apparent. The use of non-volatile interfacial tension management chemistry and the rate of change of the surface flowing pressure significantly impacted the long-term performance of the wells. The use of the IFT chemistry significantly mitigated, but did not prevent, damage arising from delay to first production or shut-ins. Based on the performance metric used, delay to first production is not beneficial. However, based on other data, the probability of improvement with IFT management was less than one in four and without IFT management was about one in eight. Once on production, the rate with which the flowing pressure was decreased had an important impact on the reservoir / wellbore connectivity. If the rate of surface flowing pressure decrease was greater than about 250 psi per day, the loss of connectivity was obvious. The last control factor was the benefit derived from using high conductivity proppants, in conjunction with the IFT management achieved with persistent Interfacial Tension Modifier fluids.
A Correlation to Evaluate the Fracture Permeability Changes as Reservoir is Depleted
Authors: He Jun , Ling Kegang , Pei Peng , Ge Jun , Qin Wenting
Published: August 2013

The increasing development of unconventional resource plays an important role in filling the gap between demand and conventional oil and gas supply. Due to the nature of low permeability, tight gas and shale reservoirs need fractures, natural and artificial, to produce hydrocarbon at commercial rates. Fracture permeability is a key factor affecting the development of these unconventional reservoirs. It is observed that fracture permeabilities decline as reservoirs are depleted because pore pressure declines lead to the closures of fractures and the permeability reductions. Therefore a correlation to quantify the fracture permeabilities varying with pore pressures is highly demanded.

In this study we investigated the effects of pore pressures on fracture permeabilities assuming constant in-situ stresses exert on the formations. Starting from the force balance, we derived equations to calculate fracture permeability based on fracture geometry. Our new correlations can also be used to evaluate the changing fracture permeability during the recovery of hydrocarbon. The proposed correlations provide a way to estimate the fracture permeability at initial pressure and the depleted pressure at any production stage. We noticed that some experiments had been conducted to build relationships between fracture permeability and pressure for some types of rocks. The empirical correlations from experiments are only as good as the databases they based on. Our research provided theoretical correlations and can be applied to any conventional and unconventional reservoirs universally. The proposed methods considered the laminar flow as well as turbulent flow in the fracture, which is often observed in gas well. Under the conditions of no core sample available to test the impact of pressure on fracture permeability, or special core analyses prohibited by cost and time, the proposed correlations are powerful tools to estimate the change of permeability with producing time.
Long Term Forecasting in Shale Reservoirs by Using Rate Transient Analysis
Authors: Gunaydin D. , He Z. , Brown K. G. , Deasy M. A. , Porter M. D. , Corinchock D. J.
Published: August 2013

Shale reservoirs have become one of the most promising natural gas resources in the energy industry. However the complex nature of shale, combined with limited production history, make predicting recovery very difficult in these reservoirs, especially early in the life of the well.

The hyperbolic form of the Arps equation has been modified for use in estimating reserves and forecasting production in shale reservoirs. Although the ease and accessibility of this method make it convenient for most applications, the Arps equation has limitations (assumes boundary-dominated flow, and assumes that flowing bottomhole pressure, drainage area, permeability and skin factor are all constant). By analyzing production data using Rate Transient Analysis (RTA) theory, analytic models can be developed and used to forecast production and recovery in shale gas reservoirs. Because RTA-based models are not subject to many of the assumptions imposed in the development of the Arps equation, these models are much more versatile than decline curves derived using the Arps modified hyperbolic equation.

In this paper, we present a practical workflow for performing RTA to determine the key performance parameters of horizontal shale wells with multiple fractures. This methodology provides a deterministic approach to estimate long term well performance in a shale reservoir. One important advantage over using the Arps equation is the ability to forecast production under different operating strategies. Using this workflow, the production and economic impacts resulting from different completion designs and operational scenarios (e.g., delayed installation of compression) can be studied.

This methodology was implemented on data sets from over 150 Marcellus Shale wells. Forecasts determined using this workflow compare favorably to the forecasts estimated by decline curve analysis and reservoir simulation. Field examples from Marcellus wells are included in this paper to demonstrate the workflow and results.