bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluating Recycled Concrete Aggregate as Hot Mix Asphalt Aggregate
Authors: Bhusal Sushanta , Wen Haifang
Published: June 2013

The use of recycled concrete aggregate (RCA) in asphalt mix is a sustainable construction practice, provided that the addition of RCA does not adversely affect the performance of the asphalt mix. In this study, the effects of RCA on the performance behavior of hot mix asphalt (HMA) were examined. The mixes were produced by blending RCA with virgin aggregate at six different percentages (0 %, 20 %, 40 %, 60 %, 80 %, and 100 %). The mix design results indicate that the RCA is highly absorptive, and that as the percentage of RCA in the mix increases, the optimum asphalt content increases significantly. In terms of performance behavior, the addition of RCA to the HMA mix reduced the modulus, resistance to rutting, fatigue, thermal cracking, and resistance to moisture damage of the asphalt mix. Considering the performance behavior and the need for a higher asphalt content, the use of RCA as HMA aggregate is not recommended, even though all the RCA mixes met the volumetric requirements. More important, the findings in this study indicate that the absorbed asphalt might play a significant role at high temperatures, likely because of expansion of the asphalt.
Outcomes of an Early Feeding Practices Intervention to Prevent Childhood Obesity
Authors: Daniels Lynne Allison , Mallan Kimberley Margaret , Nicholson Jan Maree , Battistutta Diana , Magarey Anthea
Published: June 2013

OBJECTIVE:

The goal of this study was to evaluate outcomes of a universal intervention to promote protective feeding practices that commenced in infancy and aimed to prevent childhood obesity.

METHODS:

The NOURISH randomized controlled trial enrolled 698 first-time mothers (mean ± SD age: 30.1 ± 5.3 years) with healthy term infants (51% female) aged 4.3 ± 1.0 months at baseline. Mothers were randomly allocated to self-directed access to usual care or to attend two 6-session interactive group education modules that provided anticipatory guidance on early feeding practices. Outcomes were assessed 6 months after completion of the second information module, 20 months from baseline and when the children were 2 years old. Maternal feeding practices were self-reported by using validated questionnaires and study-developed items. Study-measured child height and weight were used to calculate BMI z scores.

RESULTS:

Retention at follow-up was 78%. Mothers in the intervention group reported using responsive feeding more frequently on 6 of 9 subscales and 8 of 8 items (all, P ≤ .03) and overall less controlling feeding practices (P < .001). They also more frequently used feeding practices (3 of 4 items; all, P < .01) likely to enhance food acceptance. No statistically significant differences were noted in anthropometric outcomes (BMI z score: P = .10) nor in prevalence of overweight/obesity (control 17.9% vs intervention 13.8%; P = .23).

CONCLUSIONS:

Evaluation of NOURISH data at child age 2 years found that anticipatory guidance on complementary feeding, tailored to developmental stage, increased use by first-time mothers of “protective” feeding practices that potentially support the development of healthy eating and growth patterns in young children.
Hermansky-Pudlak Syndrome: Health Care Throughout Life
Authors: Seward Samuel L. , Gahl William A.
Published: June 2013

Hermansky-Pudlak syndrome (HPS) is a rare autosomal recessive disease that displays genetic heterogeneity; there are 9 known subtypes. HPS is characterized by oculocutaneous albinism, a platelet storage pool deficiency and resultant bleeding diathesis, and lysosomal accumulation of ceroid lipofuscin. Patients with HPS, specifically those with the genotypes HPS-1, HPS-2, or HPS-4, are predisposed to interstitial lung disease. In addition, some patients with HPS develop granulomatous colitis. Optimal health care requires a thorough knowledge of the unique health risks and functional limitations associated with this syndrome.
Systematic Review of Community-Based Childhood Obesity Prevention Studies
Authors: Bleich Sara N. , Segal Jodi , Wu Yang , Wilson Renee , Wang Youfa
Published: June 2013

OBJECTIVE:

This study systematically reviewed community-based childhood obesity prevention programs in the United States and high-income countries.

METHODS:

We searched Medline, Embase, PsychInfo, CINAHL, clinicaltrials.gov, and the Cochrane Library for relevant English-language studies. Studies were eligible if the intervention was primarily implemented in the community setting; had at least 1 year of follow-up after baseline; and compared results from an intervention to a comparison group. Two independent reviewers conducted title scans and abstract reviews and reviewed the full articles to assess eligibility. Each article received a double review for data abstraction. The second reviewer confirmed the first reviewer’s data abstraction for completeness and accuracy.

RESULTS:

Nine community-based studies were included; 5 randomized controlled trials and 4 non–randomized controlled trials. One study was conducted only in the community setting, 3 were conducted in the community and school setting, and 5 were conducted in the community setting in combination with at least 1 other setting such as the home. Desirable changes in BMI or BMI z-score were found in 4 of the 9 studies. Two studies reported significant improvements in behavioral outcomes (1 in physical activity and 1 in vegetable intake).

CONCLUSIONS:

The strength of evidence is moderate that a combined diet and physical activity intervention conducted in the community with a school component is more effective at preventing obesity or overweight. More research and consistent methods are needed to understand the comparative effectiveness of childhood obesity prevention programs in the community setting.
Intermittent hydronephrosis in childhood
Authors: Merksz Miklós , Sulya Bálint , Polovitzer Mária , Héjj Ildikó , Molnár Diana , Szepesváry Zsolt , Kiss András
Published: June 2013

Introduction: Intermittent pelviureteric junction obstruction, and its consequence,intermittent hydronephrosis is a difficult condition to identify. The renal collecting system is not dilated between the episodes of abdominal pain attacks and a prompt investigation is hard to carry out during the time of painful crisis. Therefore, most of the patients are initially misdiagnosed. Aim: The aim of the study was to assess the occurrence and the clinical characteristics of this phenomenon in children operated in the Department of Urological Surgery, Heim Pál Children Hospital, Budapest, Hungary. Patients and methods: Medical records of children operated for hydronephrosis between 2008 and 2012 were reviewed. The occurrence rate and clinical features of intermittent hydronephrosis were analyzed. Results: 76 children were operated for pelviureteric junction obstruction, of which 10 met the criteria of intermittent hydronephrosis. The average interval between the onset of symptoms and the final diagnosis was 2 years and 4 months. In 7 patients pyeloplasty, and in 3 patients nephrectomy were performed. Conclusions: Intermittent hydronephrosis represents a well-defined proportion among cases operated for hydronephrosis. The delay in diagnosis led to the loss of the kidney in one third of the patients, and this finding urges for the awareness of health professionals for this phenomenon. In case of recurrent abdominal pain of unknown etiology one must suspect a urological origin, even if a previous abdominal ultrasound showed normal kidneys. Orv. Hetil., 2013, 154, 940–946.
Stability analysis of rainfall-induced slope failure: a review
Authors: Zhang L. L. , Zhang J. , Zhang L. M. , Tang W. H.
Published: June 2013

Rainfall is one of the most significant triggering factors for slope failures in many regions around the world. Numerous research studies have been conducted to investigate infiltration of rainwater into a slope, and the effect of water infiltration on slope stability. In this paper, a review of existing research on infiltration analysis and slope stability analysis under rainfall infiltration is presented. Studies on infiltration analysis with conceptual models, analytical analysis and numerical modelling are first reviewed. The typical pore water pressure profiles in the slope are then discussed. Subsequently, recent developments in analyses of slope instabilities under rainfall conditions using the limit equilibrium method and coupled hydro-mechanical modelling are summarised, and major findings on critical hydrological factors related to rainfall-induced landslides are summarised and discussed. Finally, several research topics are suggested for further study.
Wireline Formation Testers Unlock Potential in a Deepwater Gas Condensate Reservoir
Authors: Zope Dinesh , Saxena Kamlesh Raj , Gupta Akshat , Jha Subhash , Tellapaneni Prasanna K. , Ojha Aditya , Shukla Sourabh , Jackson Richard , Jadhav Madhavi Vitthal
Published: June 2013

Reservoir-fluid properties play a key role in exploration and field development planning as accurate fluid characterization is important for designing reservoir development strategy, optimizing well completion, optimizingthe production system and efficient reservoir management. Characterization of reservoir fluids with more complex behaviors, such as gas condensates and near-critical fluids can be technically challenging, especially in a deepwater environment as reservoir development planning and production facility design is contingent on getting an accurate description of the reservoir fluid. Fluid characterization begins with the collection of representative formation fluid samples during initial wireline formation testing, bottomhole sampling and during conventional well testing operations. Traditionally these fluid samples are sent to offsite laboratories for sample analysis. However, characterizing a gas condensate fluid system based on a single sample set can be potentially misleading since PVT properties of samples acquired across a reservoir may be different due to spatial variation in their components and compositional grading. In this technical contribution we present a case study to demonstrate that characterizing gas and gas-condensate systems using only a basic set of measurements and from analysis of pressure gradients alone; could lead to potentially ambiguous results, an inappropriate fluid model or misinterpretation. In our study, we describe the practical application of advanced wireline formation sampling and testing techniques in combination with downhole fluid analysis, and their integration with laboratory PVT studies and equation-of-state (EOS) models. We describe the importance of a comprehensive data collection and fluid analysis plan early in the exploration/ appraisal process, and illustrate how high-quality fluid sample data and property measurements from advanced formation sampling and testing tools in combination with conventional well testing techniques can add significant value by helping to reduce uncertainty and aiding better technical decision making.
Hydrocarbon Production and Microseismic Monitoring – Treatment Optimization in the Marcellus Shale
Authors: Neuhaus Carl W. , Telker Cherie , Ellison Mary , Blair Keith
Published: June 2013

An integrated analysis of hydraulic fracturing treatments in the Marcellus Shale monitored by a permanently installed array of buried geophones was conducted to investigate the relationship between reservoir geology, wellbore completion and stimulation design, and microseismic data. Available data from other sources (such as well logs and well cores, information on reservoir properties, regional and local geology, and other sub-surface structural information) was utilized to determine how factors related to the specific geology in the Marcellus and to the variability of hydraulic fracture treatments impacted the microseismic response of the formation. These findings were then used to evaluate the correlation between hydrocarbon production and microseismic results relative to changes in geology and variability of the stimulation approach. The observed variability in the microseismic response under the footprint of the array was used to derive and extrapolate regional trends to optimize field development. The initial production was compared to reservoir and engineering parameters, such as treatment pressures, sequence of treatments (toe-to-heel vs. zipper-frac), net pressures, and stage spacing, to determine if the variability in the microseismic results is due to engineering differences or to spatially-varying reservoir properties.

A stress inversion based on focal mechanisms was used to explain the asymmetry of the microseismicity about the wellbore and calculate the magnitudes and directions of the three principal stresses. Fracture orientations defined by failure planes from source mechanisms were used to build a discrete fracture network (DFN) representing the existing unstimulated fracture network in the Marcellus Shale. Simulations then calculated where failure is likely to occur in the DFN during the stimulation using data obtained from the stress inversion comparing the results to the microseismic event locations. Finally, a calibrated model was used to determine the effect of changes in treatment parameters, such as flow rate, treatment pressure, and volume of fluid pumped as well as completion parameters such as stage length, number of perforations, and perforation cluster spacing, in order to optimize the hydraulic fracturing design.
Short-Term Production Prediction in Real Time Using Intelligent Techniques
Authors: Al-Jasmi A. , Goel H. K. , Nasr H. , Querales M. , Rebeschini J. , Villamizar M. A. , Carvajal G. A. , Knabe S. , Rivas Francklin , Saputelli L.
Published: June 2013

Intelligent digital oilfield operations collect real-time data from an operating asset and transform that raw data into information through intelligent, automated work processes, which assist engineers with key well operations and monitoring, improving their productivity and decision-making. A major oil and gas operator in the Middle East is developing a set of intelligent workflows for key activities and processes for its production operations, with the ultimate goal of improved asset performance.

Real-time surveillance and monitoring of production operation processes have proven to be operationally and economically important for managing complex, high-cost reservoirs. However, predicting short-term production and production interruptions—for example, related to pump settings—has posed a tremendous challenge. While operators routinely forecast production for the next 60 to 90 days, sophisticated tools such as full-field numerical simulation models are of limited use in predicting short-term production of 30 days. Similarly, while nodal analysis can estimate current operating conditions, it cannot be used for prediction. Because of its simplicity, rapid training, and demonstrated results, a prediction technique using neural networks (NN) has emerged as a solution that can predict short-term well production behavior with acceptable accuracy.

This paper presents a case study using NNs to predict liquid rate and water cut performance in a mature reservoir with more than 20% water cut. The NN was trained using available surface and down-hole, real-time production data, time-dependent data, and completion design data. The time-dependent data are included as time series configured to let users generate scenarios by changing well operations. This approach not only provides a base-case prediction but also simulates results after making adjustments in control variables, such as tubing head pressure (THP) and pump frequency. Changing THP and frequency lets users model production to predict and circumvent negative well pump events.

This project was implemented in a mature carbonate oil reservoir under waterflood in the Middle East. Despite limited reservoir data, the results show that the NN is a powerful and rapid tool that predicts liquid rate and water cut with acceptable accuracy, helping engineers make prompt decisions to prevent and reduce downtime.
Combining Geostatistics With Bayesian Updating to Continually Optimize Drilling Strategy in Shale Gas Plays
Authors: Willigers B. J. , Begg S. , Bratvold R. B.
Published: June 2013

We present a new methodology for improving the economic returns of shale gas plays. The development of an economically efficient drilling programme in such plays is a challenging task, requiring a large number of wells. Even after a relatively large number of wells have been drilled, the average well production and the variation of well performance (economics) remains highly uncertain. The ability to delineate a shale play with the fewest number of wells and to focus drilling in the most productive areas is an important driver of commercial success.

The importance of probabilistic modelling in managing uncertainty in shale gas plays has been explicitly emphasised in a number of studies. The objective of this study is to develop a practical valuation methodology that addresses these complexities and is dynamic, in the sense that the optimal drilling strategy can be continually updated as we learn the outcome of each well drilled.

Maximizing the returns from a shale gas play is essentially a problem of choosing well locations and numbers to optimize production volumes & rates. Drilling policies have to take account of a large number of already-drilled locations, possible new drilling locations, spatial dependencies between performance at those different (possible) well locations and the extent of uncertainty as to whether or not a well will be economic. These factors cause typical valuation methodologies to be impractical due to the "curse of dimensionality".

In this study an unconventional play is divided into cells. In each cell a fixed number of wells can be drilled. The chance of success (of a well having an NPV greater than zero) in any given cell is itself considered to be an uncertain variable. An initial probability distribution for the chance of success of each cell is derived from analogous plays plus any available information about the specific play.

The methodology proceeds as follows. First, as each new well (or group of new wells) is drilled, the outcome is used in combination with the prior probability distribution (using Bayes Theorem) to create an updated probability distribution for the chance of success of the relevant grid cell. Thus, our initial estimate can be continuously updated as we get more and more actual outcomes. Second, the influence of the new chance of success on the surrounding cells, due to spatial correlation, is updated using indicator kriging, a geostatistical technique.

The methodology proposed in this study informs the development of drilling policies for shale gas opportunities by using a probabilistic model that accounts for the uncertainty in the chance of success and its spatial dependency. The use of cells to represent a set of wells simplifies the analysis and greatly reduces the computing requirements. The methodology has been applied to a well set from the Barnett Shale, Texas, United States of America.
Sustainability versus Sustainable Development: The Case of Shale Gas
Authors: Shields Deborah , Verga Francesca , Blengini Gian Andrea
Published: June 2013

There is an ongoing dialogue in society about the place of energy resources in sustainability. One aspect of that discussion focuses on resource sustainability, the ability of governments and industry to ensure continued supply of needed resources. A related topic centers on the economic benefits and costs of fossil fuel production. Concerns about negative impacts on environmental social sustainability drive other parts of this conversation, and often lead to opposition to fossil fuel production and use. This paper uses the example of shale gas to argue that concentration on single sustainability aspects is inappropriate. Rather, development and production of these resources needs to be considered in the context of sustainable development, which necessitates integrating environmental and development strategies so as to satisfy current and future human needs. Integrated Sustainability Assessment (ISA) is proposed as a way to analyse the net contributions of a shale gas play to economic, environmental, social and resource sustainability. The latter topic is considered and variables that could be used in an ISA are proposed. Understanding, quantifying and communicating the nature and magnitude of the net contribution of shale gas to society will be a challenging, but essential, task in the process of responding to opposition in an open and constructive manner, one which ISAs can support.
How to integrate basin-scale information into reservoir models
Authors: Quinto Sacchi , di Torino Politecnico , Jan Weltje Gert
Published: June 2013

Objectives and scope of the Study In this paper a new approach is presented to consistently integrate basin-scale information into reservoir models. The impact of the quantitative integration of boundary conditions derived from basin-scale modeling on the facies distribution at the reservoir scale is evaluated. To this purpose, a new workflow was defined based on a geostatistical approach. The aim was that of integrating the typical dataset for reservoir geological modeling, comprising well and seismic data, with a potentially new kind of data obtained from 3-D process-based stratigraphic modeling and related to the distribution of the hydrocarbon bearing volumes. Quantitative coherence between the small scale reservoir volume and the large-scale geological setting defined by the basin model was imposed. Synthetic case studies were set up to verify the effectiveness of the method.

Applications The entire process was applied to a fluvio-deltaic environment to integrate the basin-derived information, such as (1) the overall reservoir/non reservoir volumes, (2) the 3D distribution of channelized volumes and (3) related flow directions, to the reservoir model. Eventually, the uncertainty reduction in the description of the final facies distribution at the reservoir scale was evaluated.

Results, Observations and Conclusions The developed approach proved very efficient to estimate the lithological fraction of the hydrocarbon bearing rocks (i.e. sands in a shaley/clayey environment). The lithological fraction is of crucial importance during the appraisal phase of a reservoir when relevant decisions have to be taken but few wells are drilled and, as a consequence, a limited amount of data is available to perform a reliable volumetric estimate. Furthermore, the prediction of the 3D facies architecture (such as the channel pattern in a fluvial depositional environment) can effectively assist in the well planning strategy. Besides, the overall uncertainty affecting a reservoir model can be assessed; this uncertainty is both a function of the initial environmental parameters for basin modeling and of the adopted methodological approach for basin-to-reservoir data integration. Therefore, an accurate inference of the basin parameters is needed to achieve a reliable prediction of both the channel location and the sand/shales volumes fractions.

Significance of subject matter Reservoir modeling can significantly benefit from the integration of quantitative basin-scale information. In particular, the numerical modeling of the stratigraphic sequence can be used to steer the reconstruction of the reservoir internal geometry and to reduce the uncertainty in the distribution of the hydrocarbon-bearing lithologies. Furthermore, this approach provides a rigorous assessment of the information content of all the available data and thus it might be very useful to guide further data acquisition campaigns.
Effect of DFN Upscaling on History Matching and Prediction of Naturally Fractured Reservoirs
Authors: Elfeel Mohamed Ahmed , Jamal Sarim , Enemanna Chukwuemeka , Arnold Dan , Geiger Sebastian
Published: June 2013

Naturally Fractured Reservoirs (NFR) hold a significant fraction of remaining petroleum reserves. Recovery factors from NFR are usually less than in conventional reservoirs due to associated high uncertainty throughout the characterisation and modelling phases. This particularly includes the modelling and upscaling of the fracture domain using Discrete Fracture Networks (DFN).

Computer assisted history matching and prediction is becoming increasingly popular as they help finding multiple history-matched models and probabilistic forecasts. Therefore, the associated uncertainty can now be quantified in a limited time frame. However, the results of a history match are known to depend on initial reservoir properties, including fracture permeability and matrix shape factors. Geological uncertainty in these two factors is exacerbated by the DFN upscaling errors.

We show how DFN modelling can be used to increase geological prior knowledge and hence produce more geologically consistent models. To highlight DFN upscaling errors, we use a realistic dataset from an onshore fractured reservoir to show how the DFN upscaling error could propagate through to the history matching phase. We compare history matching of three models with different DFN upscaling processes.

Results from state-of-the-art assisted history matching and prediction were found to depend on the static properties and particularly the computation of effective fracture permeability during DFN upscaling. This upscaling error alone leads to very different reservoir models, despite the best history matched models being of comparable quality. Hence, this leads to more uncertainty in reservoir production forecast. The identification of DFN upscaling errors is therefore crucial for better uncertainty quantification in reservoir simulation of NFR.
A Numerical Model for Multi-Mechanism Flow in Shale Gas Reservoirs with Application to Laboratory Scale Testing
Authors: Swami Vivek , Settari A. (Tony) , Javadpour Farzam
Published: June 2013

Shale is a complex unconventional reservoir having a variety of storage and flow mechanisms coupled together. Contrary to conventional reservoirs where gas is stored only in the pore space as free gas; current numerical simulators assume gas is stored as free and adsorbed phase in shale. Recent advancement of visualization and measurement techniques has enabled us to look at shale more closely. Shale has been found to contain a well-developed nanopore network in the organic matter or kerogen. Correspondingly we believe that gas is stored via four storage mechanisms: gas in natural fractures, free gas in matrix pores, adsorbed gas and gas dissolved in kerogen bulk in the shales.

In this work we formulate a flow model for shale gas reservoirs including the physics at nano scale. The model incorporates the gas stored in micro-fractures, gas stored in nanopores, gas adsorbed on the pore walls and gas dissolved in kerogen bulk. This complex quad porosity system has coupled equations between three interconnected systems; between matrix and fracture set, between matrix and adsorbed gas and between matrix and kerogen bulk. Sets of governing equations were derived for the coupled systems and numerically solved to find gas production as a function of time. The model was validated against laboratory observed data for a shale canister test from a Canadian shale gas field. This laboratory scale model can be suitably up-scaled for field scale simulation of shale reservoirs.
Well-head Pressure Transient Analysis
Authors: Spyrou Charidimos E. , Nurafza Peyman R. , Gringarten Alain C.
Published: June 2013

Pressure Transient Analysis (PTA) of bottom-hole pressure data (BHP) is a well-established method for estimating reservoir flow parameters and identify well behaviour. Unfortunately, permanent recording of bottom-hole data is not always operationally possible, for example in the case of high pressure and high temperature (HP/HT) reservoirs. On the other hand, most wells are equipped with gauges at the well head which record well head pressure data (WHP) continuously. This paper investigates the feasibility of using WHP data for identifying well test behaviour. The objective is to assess the ability to derive key well and reservoir parameters from WHP data in the absence of BHP data, focusing primarily on the estimation of permeability and skin.

Three different actual reservoir fluid and wellbore conditions were studied: a water injector with a single phase fluid in the wellbore and a reasonably constant fluid density; a dry gas well, also with single phase in the wellbore but changing fluid density; and a gas condensate well with multiphase flow and varying density in the wellbore. In each case, both WHP and BHP data were available. These WHP and BHP data were analysed separately with conventional PTA methods in order to compare resulting permeabilities and skin factors. WHP data were then converted to BHP data, using methods available in the literature in the water and dry gas cases, and two different approaches developed in this work for the gas condensate case.

In the case of the water injector, analysis of both the original WHP data and the converted BHP data provides a good estimate of permeability while overestimating the skin factor. A correction can be applied to the WHP derived skin, to match the BHP skin value.

In the dry gas and gas condensate cases, WHP analysis overestimates both permeability and skin factor. In the dry gas case, the WHP derived permeability and skin can be corrected to yield the BHP values, whereas PTA on the converted BHP data does provide the correct permeability. Finally, in the gas condensate case, it is possible to obtain the correct permeability from converted BHP in the absence of phase redistribution, whereas the skin factor remains overestimated.
Use of Well Indicators in the Production Strategy Optimization Process
Authors: Botechia V. E. , Gaspar A. T. , Schiozer D. J.
Published: June 2013

The selection of an adequate strategy for oil production is a complex process due to the several parameters that must be taken into account: type, number and position of wells, production and injection capacities of platforms, which must be defined and optimized in order to achieve an exploitation strategy which provides the best possible economic return. Most works presented production strategy optimization methodologies based on production or Net Present Value (NPV). In general, well information is not used in the optimization processes. However, information on well behavior and performance is very important to improve the production strategy and to make the process more robust.

The aim of this paper is to present a comparative analysis of the use of different indicators in order to assist the selection/optimization of a production strategy based on well information, using numerical simulation and economic analysis. Changes in the configurations of the production system can be made according to the behavior of the wells and evaluation of the indicators aiming to maximize the NPV of the field. The development of the equations of the well indicators is shown and the methodology is applied to two different geological models: an offshore sandstone reservoir, representing a gas solution drive model and a carbonate reservoir with typical characteristics of the pre-salt areas of Brazil.
A Novel Approach to a Quantitative Estimate of Permeability from Resistivity Log Measurements
Authors: Viberti Dario , Cossa Alessandro , Galli Maria Teresa , Pirrone Marco , Salina Borello Eloisa , Serazio Cristina
Published: June 2013

Description of the material

In this paper a novel methodology for the estimation of the formation permeability, based on the integration of resistivity modeling and near wellbore modeling, is presented. Results obtained from the application to a real case is shown and discussed.

The well log interpretation process provides a reliable estimation of the main petrophysical parameters such as porosity, fluid saturations and shale content, but the formation permeability is traditionally obtained through laboratory tests on plugs, at the scale of centimeters, and through well test interpretation, at the scale of tens or hundreds of meters.

However, log measurements, and in particular resistivity logs, are strongly affected by the presence of the near wellbore zone invaded by mud filtrate. In turn, the extension of the invaded zone depends on formation properties and, in particular, on permeability.

As a consequence, the resistivity measured by the tools (the apparent resistivity) has to be properly corrected through a resistivity modeling process to obtain the true formation resistivity and the geometry and resistivity of the invaded zone.

Resistivity profiles within the invaded zone are function of fluid properties, petrophysical properties and rock-fluid interaction properties. The novelty of the approach is to numerically simulate the mud invasion phenomenon and match the resistivity profile provided by resistivity modeling to estimate the formation permeability. In the proposed methodology the match of the resistivity profile is obtained by integrating the near wellbore simulator with an optimization algorithm.

Application

This novel approach was applied to a heterogeneous shaly-sand oil-bearing reservoir in the Norwegian offshore area. The analyzed sequence was characterized by a high degree of variations in the layers’ thickness, from meters down to below tools’ vertical resolution. A complete set of wireline logs were acquired in the considered well; several cores were cut and routine and special core analyses performed.

Results, Observations, and Conclusions

First, a conventional petrophysical characterization was achieved and the appropriate resistivity corrections were calculated. Then, the modeled resistivity was used as the input for the optimization algorithm so as to obtain a continuous quantitative estimation of permeability in the entire logged interval. The results were satisfactorily compared to core measurements: in both thick, conventional layers and thinner beds the match was very accurate.

Significance of subject matter

The new approach provided a robust permeability estimate also in un-cored intervals and, more generally, can be used to predict permeability in un-cored and un-tested wells.
Local History Matching Using 4D Seismic Data and Multiple Models Combination
Authors: Davolio Alessandra , Maschio Célio , Schiozer Denis José
Published: June 2013

Nowadays there are several methodologies to incorporate quantitatively 4D seismic data in the history matching of reservoir simulation models. Most of them add a map attribute derived from 4D seismic, which can be impedance maps, saturations etc., in the objective function of the optimization process. In these cases, the goal is to match the dynamic information provided by 4D seismic with simulation response in the whole reservoir area, or the whole area covered by seismic data. In this work, it is proposed a history matching methodology that uses 4D seismic information locally for each injector (and the associated producers) individually, trying to match the water front movement related to each injector with the observed dynamic changes. In order to guarantee consistency with geology, the matching is done by combining static properties that comes from different simulation models. These models are generated through a combination of the most important uncertain parameters in an uncertainty analysis procedure, geologically consistent, that should be run previously. Then, the matching procedure is based on the computation of the water saturation errors at some sub-regions defined around the injector for multiple scenarios; the error is computed between water saturation derived from 4D seismic and each model simulation result. The models which presented the smallest error for each sub-region are selected and a new simulation model is built by combining the static properties extracted from the selected models at each sub-region. Before calculating the saturation errors the volume of water computed from 4D seismic is calibrated to the volume of injected water providing a more robust calibration. The methodology was applied to a synthetic case where porosity and permeability were the main uncertainties updated by the methodology proposed. Since these properties were generated through geostatistic realizations, the adjusted model kept the geological features. The promising results observed in the synthetic case showed that the methodology can be a good alternative for history matching, since it is an easy to implement procedure and it does not require sophisticated optimization algorithms to incorporate 4D seismic into the process.
A Novel Approach to Modeling and Forecasting Frac Hits in Shale Gas Wells
Authors: Lawal Hamed , Jackson Greg , Abolo Nnamdi , Flores Cecilia
Published: June 2013

The ultra-tight nature of shale reservoirs has resulted in the maximization of the stimulated area within a section to increase production. As a result, some wells appear to interfere with one another during stimulation. This interference has been known to typically reduce (occasionally enhance) the performance of wells currently in production by altering the existing fracture network, or near well permeability, via the presence of multiple phases. This process is known as a "frac hit". Three different mechanisms are thought to be possible causes of the well-to-well interaction: depleted zones, changing stress fields, and high permeability lithofacies. Numerical and analytical modeling will be used to explore the impact of dynamic completion systems.

In this paper, modeling techniques are demonstrated to allow operators the ability to use rate transient analysis (RTA) tools to model frac hits. Examples from the Haynesville and Marcellus are examined. The examples were categorized based on the dominant flow regime, transient linear flow or depletion flow, and then the proper technique was employed. Unique characteristics with respect to reservoir phenomenon, i.e. depleted zone, changing stress fields, or high permeability lithofacies are also discussed.

These modeling procedures will enable operators to bound forecasts for wells that have been altered by the stimulation of a neighboring well. This means operators can still provide risked reserves based on numerical modeling and RTA software for wells that have endured a hit. In addition, the techniques will be applied to re-fracturing. Now operators have the ability to forecast re-fractured wells quantifying the NPV of a re-fracture. Lastly, the knowledge gained from the in-depth examination of the phenomenon and drive mechanisms behind the frac hit enables the avoidance of future occurrences of well damage.
Enhancing the Performance of Viscoelastic Surfactant Fluids Using Nanoparticles
Authors: Gurluk Merve R. , Nasr-El-Din Hisham A. , Crews James B.
Published: June 2013

Viscoelastic surfactant (VES) based fluids are used in many applications in the oil industry. Their viscoelastic behavior is due to the overlap and entanglement of long wormlike micelles. The growth of these wormlike micelles depends on the charge of the head group, salt concentration, temperature, and the presence of other interacting components. The problem with these surfactants is that they are expensive and used at temperatures less than 200°F.

The viscoelasticity of nanoparticle-networked VES fluid systems were analyzed by rotational and oscillatory viscometers. Apparent fluid viscosities were measured by using 2–4 vol% amidoamine oxide surfactant in 13 to 14.2 ppg CaBr2 brines and 10.8 to 11.6 ppg CaCl2 brines at different temperatures up to 275°F and a shear rate of 10 s−1. The nanoparticles evaluated were MgO and ZnO at 6 pptg concentration. In addition, the effect of different nanoparticle concentrations (0.5 to 8 pptg) and particle size on the viscosity of VES fluid was investigated. The oscillatory shear rate sweep (100 to 1 s−1) was performed for the 4 vol% VES in 14.2 ppg CaBr2 from 100 to 250°F.

This study showed that the addition of nanoparticles improved the thermal stability of VES micellar structures in CaBr2 and CaCl2 brines up to 275°F and showed an improved viscosity yield at different shear rates. Micron and nano-size particles have potential to improve the viscosity of VES fluids. Lab tests show for VES micellar systems without nanoparticles, the dominant factor is the viscous modulus but when nanoparticles are added to the system at 275°F the elastic modulus becomes the dominant factor. These positive effects of nanoparticles on VES fluid characteristics suggest that these particles can reduce treatment cost and will extend the temperature range of the surfactants to 275°F.
History Matching Of The Norne Full Field Model Using An Iterative Ensemble Smoother
Authors: Chen Yan , Oliver Dean S.
Published: June 2013

Although ensemble-based data assimilation methods such as the ensemble Kalman filter and the ensemble smoother have been extensively used for history matching of synthetic models, the number of applications of ensemble-based methods for history matching of field cases is extremely limited. In most of the published field cases in which the ensemble-based methods were used, the number of wells and the types of data to be matched were relatively small. As a result, it may not be clear to practitioners how a real history matching study would be accomplished using ensemble-based methods.

In this paper, we describe the application of the iterative ensemble smoother to the history matching of the Norne field, a North Sea field, with a moderately large number of wells, a variety of data types, and a relatively long production history. Particular attention is focused on the problems of identification of important variables, generation of an initial ensemble, plausibility of results, and efficiency of minimization. We also discuss the challenges encountered in using ensemble-based method for complex field case studies that are not typically encountered in synthetic cases.

The Norne Field produces from an oil and gas reservoir discovered in 1991 offshore Norway. The full field model consists of four main fault blocks that are in partial communication and many internal faults with uncertain connectivity in each fault block. There have been 22 producers and 9 injectors in the field. Water alternating gas injection is used as the depletion strategy. Production rates of oil, gas and water of 22 producers from 1997 to 2006 and RFT pressure from 14 different wells are available for model calibration. The full field simulation model has 22 layers each with dimension 46 by 112 cells. The total number of active cell is about 45,000.

The Levenberg-Marquardt form of the iterative ensemble smoother (LM-EnRML) is used for history matching the Norne full field model using production data and RFT pressure. The model parameters that are updated include permeability, porosity and net-to-gross ratio at each gridblock, vertical transmissibility at each gridblock for six layers, transmissibility multipliers of 53 faults, end-point water and gas relative permeability of four different reservoir zones, depth of water-oil contacts and transmissibility multipliers between a few main fault blocks. The total number of model parameters is about 150,000. Distance-based localization is used to regularize the updates from LM-EnRML. LM-EnRML is able to achieve improved data match compared to the manually history matched model after three iterations. Updates from LM-EnRML do not introduce artifacts in the property fields as in the manually history matched model. The automated workflow is also much less labor intensive than manual history matching.
Fracture Mobility Control by Polymer Gel- Integrated EOR in Fractured, Oil-Wet Carbonate Rocks
Authors: Brattekås B. , Haugen Å. , Ersland G. , Eide Ø. , Graue A. , Fernø M. A.
Published: June 2013

This work experimentally investigates a two-step, integrated EOR technique for heavily fractured, oil-wet carbonate rocks by combining fracture mobility control and chase fluid injections for increased sweep. The combination of mobility control using a cross-linked Cr(III)-Acetate HPAM polymer gel, and three different chase fluids (water, surfactant or CO2 foam) was investigated as an integrated EOR approach. Waterflood oil recovery was low with poor sweep efficiency and oil production from the fracture volume only. Fracture conductivity was significantly reduced after polymer gel placement in the fracture, leading to increased sweep and oil recovery during chase fluid injections, with oil recoveries up to 60%OOIP.
Solvent-enhanced Spontaneous Imbibition in Fractured Reservoirs
Authors: Chahardowli Mohammad , Zholdybayeva Almagul , Farajzadeh Rouhi , Bruining Hans
Published: June 2013

Oil recovery in fractured reservoirs by water flooding critically depends on the wetting properties of the matrix blocks between the fractures. The recovery from oil-wet reservoirs is small. In incompletely oil-wet systems, the presence of initial water may change the wettability characteristics so that imbibition and some oil recovery can occur. The hypothesis in this work is that water-soluble solvent (diethyl ether) improve the ultimate recovery and the imbibition rate in partially and completely water-wet cores. The main recovery mechanisms are the wettability change of the partially water-wet cores and oil swelling and the oil viscosity reduction in both partially and completely water-wet cores.

This paper reports an experimental study concerning the recovery enhancement by water-soluble solvent (diethyl ether). We used an Amott imbibition cell studying oil saturated samples of various wettabilities, permeabilities using oils of different viscosities and two different diethyl ether (solvent) concentrations in the aqueous phase. In the first stage of the experiment, the completely water-wet core was exposed to brine without solvent. In a second stage, the core was put in a new Amott cell that was filled with solvent/ brine mixture. The extra recovery by solvent/brine mixture strongly depends on the residual oil saturation after brine imbibition and it is relatively insensitive to the permeability of the core or the oil viscosity. Therefore, larger residual oil saturation resulted in a higher extra recovery.

For the partially water-wet samples, we also started with exposing the core to pure brine without solvent. Contrary to the completely water-wet samples, there was a significant increase in recovery rate when the sample is transferred to another Amott cell where it is exposed to a mixture of solvent and brine. In view of large values of the inverse Bond number in both partially and completely water-wet cores, the transfer between matrix and fracture capillary driven.
Integrating Price Path Uncertainty Into Optimal Extraction Path Analysis of Unconventional Liquids Rich Reservoirs
Authors: Ozkan Sarp , Ozkan Erdal
Published: June 2013

The acquisition of unconventional assets has become viable under current technical and economical conditions. While producing the conventional resources, utilizing the reserve replacement potential offered by the unconventional reservoirs has brought up optimal extraction path considerations. Optimal extraction path analyses mainly focus on the timing of incorporating unconventional production within a company’s portfolio. This paper establishes a decision making framework that takes into account that different price scenarios can unfold with differing probabilities of occurrence and that switching from conventional to unconventional production comes at a cost. The model is based on an integrated discounted cash flow and optimization formulation to find the differing parameters necessary to populate a decision tree framework. A series of differing price paths are considered for a company with exogenously assigned probabilities of occurrence and an optimal path analysis is conducted under different assumptions regarding its risk propensity. A sensitivity analysis is also conducted on the probabilities of different price scenarios to better understand the risk the company faces in making production decisions. Using the framework introduced in this paper, a company should be able to make a more informed decision that considers price path uncertainty and risk preferences in the timing of the switch from conventional to unconventional production.