bluuebunny/crossref_metadata_2025 huggingface dataset:
Seroprevalence rates of antibodies againstLeishmania infantum and other protozoan and rickettsial parasites in dogs
Authors: Paulan Silvana de Cássia , Lins Aline Gouveia de Souza , Tenório Michely da Silva , Silva Diogo Tiago da , Pena Hilda Fátima de Jesus , Machado Rosangela Zacarias , Gennari Solange Maria , Buzetti Wilma Aparecida Starke
Published: June 2013

Canine visceral leishmaniasis (CVL) is caused by the protozoan Leishmania infantum, which infects dogs and humans in many regions of Brazil. The present study involved an indirect fluorescent antibody test (IFAT) to analyze L. infantum,Ehrlichia spp., Babesia canis,Toxoplasma gondii and Neospora caninuminfection rates in serum samples from 93 dogs in a rural settlement in Ilha Solteira, SP, Brazil. The seroprevalence rates of anti-L. infantum, anti-Ehrlichia, anti-B. canis, anti-T. gondii and anti-N. caninum antibodies were 37.6%, 75.3%, 72%, 47.3% and 6.4%, respectively. In addition to IFAT, direct microscopic examination of popliteal lymph node aspirates revealed 26.9% of CVL positive dogs. Serological tests revealed that 17.2% of the dogs were seropositive for a single parasite, 29% for two parasites, 33% for three, 16.1% for four, and 1.1% for five parasites, while 3.2% were seronegative for five parasites. The presence of antibodies against these parasites in serum samples from dogs confirmed their exposure to these parasites in this rural area. Because of the potential zoonotic risk of these diseases, mainly leishmaniasis, ehrlichiosis and toxoplasmosis, special attention should focus on programs for the improvement of diagnostic assays and control measures against these parasites.
Settlement analysis of shallow foundations on sand
Authors: Bovolenta Rossella
Published: June 2013

The evaluation of ground movements is one of the most important issues in geotechnical engineering applications. In this context, the paper is aimed at prediction of the load–settlement performance of shallow foundations by taking soil non-linearity into account. The approach illustrated is based on the operational stiffness concept, characterising field behaviour with reference to relative foundation settlements, indicating pseudo-strain levels. A strain correction factor and a modulus correction factor, relating laboratory and field stiffness degradation curves, are introduced. Values of these factors are supplied on the basis of well-documented tests performed on Ticino sand, and can be adopted in elastic relationships for the prediction of load–settlement curves. The procedure, developed in order to supply the designer with a practical tool, is described, and some applications are presented.
Estimating transitions between states using measurements with imperfect detection: application to serological data
Authors: Choquet Rémi , Carrié Cécile , Chambert Thierry , Boulinier Thierry
Published: June 2013

Classifying the states of an individual and quantifying transitions between states are crucial while modeling animal behavior, movement, and physiologic status. When these states are hidden or imperfectly known, it is particularly convenient to relate them to appropriate quantitative measurements taken on the individual. This task is, however, challenging when quantitative measurements are not available at each sampling occasion. For capture–recapture data, various ways of incorporating such non‐discrete information have been used, but they are either ad hoc and/or use a fraction of the available information by relying on a priori thresholds to assign individual states. Here we propose assigning discrete states based on a continuous measurement, and then modeled survival and transition probabilities based on these assignments. The main advantage of this new approach is that a more informative use of the non‐discrete information is done. As an illustrative working example, we applied this approach to eco‐epidemiological data collected across a series of years in which individuals of a long‐lived seabird, the Black‐legged Kittiwake (Rissa tridactyla), could either be visually detected or physically recaptured and blood sampled for subsequent immunological analyses. We discuss how this approach opens many perspectives in eco‐epidemiology, but also more broadly, in population ecology.
How climate extremes—not means—define a species' geographic range boundary via a demographic tipping point
Authors: Lynch Heather J. , Rhainds Marc , Calabrese Justin M. , Cantrell Stephen , Cosner Chris , Fagan William F.
Published: June 2013

Species' geographic range limits interest biologists and resource managers alike; however, scientists lack strong mechanistic understanding of the factors that set geographic range limits in the field, especially for animals. There exists a clear need for detailed case studies that link mechanisms to spatial dynamics and boundaries because such mechanisms allow us to predict whether climate change is likely to change a species' geographic range and, if so, how abundance in marginal populations compares to the core.

The bagwormThyridopteryx ephemeraeformis(Lepidoptera: Psychidae) is a major native pest of cedars, arborvitae, junipers, and other landscape trees throughout much of North America. Across dozens of bagworm populations spread over six degrees of latitude in the American Midwest we find latitudinal declines in fecundity and egg and pupal survivorship as one proceeds toward the northern range boundary. A spatial gradient of bagworm reproductive success emerges, which is associated with a progressive decline in local abundance and an increase in the risk of local population extinction near the species' geographic range boundary.

We developed a mathematical model, completely constrained by empirically estimated parameters, to explore the relative roles of reproductive asynchrony and stage‐specific survivorship in generating the range limit for this species. We find that overwinter egg mortality is the biggest constraint on bagworm persistence beyond their northern range limit. Overwinter egg mortality is directly related to winter temperatures that fall below the bagworm eggs' physiological limit. This threshold, in conjunction with latitudinal declines in fecundity and pupal survivorship, creates a nonlinear response to climate extremes that sets the geographic boundary and provides a path for predicting northward range expansion under altered climate conditions. Our mechanistic modeling approach demonstrates how species' sensitivity to climate extremes can create population tipping points not reflected in demographic responses to climate means, a distinction that is critical to successful ecological forecasting.
Investigation of Two-Phase and Three-Phase Relative Permeability in Different Rocks with Similar Pore Size Distribution
Authors: Shahverdi H. , Sohrabi M. , Fatemi S. M. , Ireland Shaun
Published: June 2013

Relative permeability (kr) function describes the comparative ease by which different fluids flow in a porous medium and plays an influential role in numerical simulation of petroleum reservoirs. Since, the measurement of relative permeability, especially three-phase ones, in laboratories is time consuming and expensive, much research has directed towards developing correlations for estimating the three-phase relative permeability values. One assumption used in reservoir simulation is that relative permeability curves of different rocks with similar lithology and pore size distribution depict identical behaviour if expressed against normalised (mobile) fluid saturations. This paper present the results of a study carried out to assess the validity of this assumption for two-phase and three-phase flow systems.

A set of two-phase (oil/gas) and three-phase (oil/gas/water) unsteady-state coreflood experiments were conducted on two Clashach sandstone samples with permeabilities of 1000 mD and 65 mD. The relative permeability curves for each experiment were then obtained by mathematical modelling of the coreflood tests and matching the laboratory measured data.

Comparison between the measured two-phase oil/gas kr of the two cores show that the relative permeability curves versus mobile (normalized) saturation for the 1000 mD core are close to that of the 65 mD rock. This demonstrates that in the absence of measured relative permeability data for a low permeability core, the available data for a higher permeability core with similar lithology can be used for the low permeability rock and vice versa. However, this was not the case for three-phase kr. Comparison of the three-phase relative permeability obtained for water, oil and gas in the two cores shows significant difference for the two cores even when plotted againest normalized saturations. Hence, the simulation of the coreflood experiment involving three-phase flow carried out on the 65 mD core using the relative permeabilities of the 1000 mD core led to highly erroneous predictions. These results reveal that three-phase kr of one rock is not representative of the fluid mobility in another rock. The main conclusion drawn from this study is that scaled three-phase relative permeability in different cores behaves thoroughly different even if their pore size distributions are very similar. The disagreement observed between relative permeability of the two rocks could be attributed to the different magnitude and variations of capillary forces being active during the governing multiphase flow events.
Dependency of Wettability Alteration on Hydrocarbon Composition and Interfacial Tension in Gas/Condensate Systems
Authors: Fahimpour J. , Jamiolahmady M. , Sohrabi M. , Mills J.
Published: June 2013

In gas-condensate reservoirs, soon after the pressure falls below the dew-point pressure, condensate liquid drops out of the gaseous phase. In such conditions, high surface energy minerals render spreading of the condensate film on the rock surface, wetting out the pores’ surfaces. Condensate consequently starts to accumulate, restricting the open paths for the flowing gas, which could result in significant reduction in well productivity.

Modifying the surface energy of the reservoir minerals by chemicals, aiming at altering the rock wettability from strongly liquid-wetting to intermediate gas-wetting conditions, has been proposed as a solution to improve the oil mobility around the wellbore and mitigate the corresponding blockage issues.

Over the last decade, large numbers of experimental investigations have been dedicated to study the performance of different chemical groups on wettability alteration of reservoir rocks. However, in all these studies, conventional fluids, e.g. decane/air, have been used to measure the contact angles at oil/gas/rock boundary. In this paper, for the first time, gas/condensate fluids, with various compositions and at different interfacial tensions (IFTs) have been used to evaluate the performance of wettability modifiers under more realistic conditions. The observations revealed that at similar IFT values, as the number of carbon atoms increases, i.e. there are heavier hydrocarbons (e.g. C1/nC10), the condensate/gas/treated rock contact angle (θcondensate/gas) increases, whilst for the lighter hydrocarbons (C1/nC4), the condensate wets the rock surface quickly. IFT also showed a significant impact on the treatment performance. That is, at lower IFTs, smaller contact angles through the liquid phase were observed, e.g. for C1/nC10 mixture, when IFT decreased from 10 to 1.5 mN/m, θcondensate/gas reduced from 65° to 40° towards liquid-wet.

The results highlight the significance of the dependency of the wettability modifiers performance to the original fluid composition and thermodynamic conditions in a gas-condensate reservoir. This also underlines the careful considerations that are required in design and application of these treatments in such reservoirs.
Upscaling and Downscaling with an Effective Medium Theory, Applied to Heterogeneous Reservoir
Authors: Brouwer G. K. , Fokker P. A.
Published: June 2013

Upscaling of reservoir permeability will remain an issue in the oil and gas industry as long as static and dynamic models are limited by computing power and memory constraints. At the same time, flow predictions are required at the scale of the static model. A feasible approach is the subsequent application of upscaling and downscaling: upscaling to be able to make reservoir-scale flow simulations and downscaling to map the results of these calculations on the underlying geological grid.

We propose a procedure which mimics the behavior of non-scaled reservoir models better than conventional methods. Our method entails a new non-local upscaling and downscaling procedure inspired by effective medium theories. The most important difference with standard techniques is the choice of boundary conditions. Our boundary conditions are based on the physical situation rather than on an ad-hoc pressure and/or flow condition on the boundaries of the region to be upscaled.

We demonstrate our procedure with three examples. The first example entails a simple problem where a 2x2 block region is upscaled and it is shown that conventional procedures break down. The physical explanation is given in terms of a flow disturbance outside the scaled area not honored by these techniques.

The second example is a more complicated problem with apparent geological channeling. In the first place, the upscaling provides a good match of the fine-scale dynamic model. Even more important, however, are the downscaled flow velocities resulting when introducing the boundary conditions obtained from the coarse scale for the local fine scale. These show a faithful representation of the channel flow as also obtained with the fine-scale model, while results of attempts to achieve the same with conventional technology did not.

The third example is a 3-dimensional model available from the literature. Again, our upscaled and downscaled results were in close agreement with the full fine-scale simulation.

The current technique does not account for relative permeabilities and capillary pressures. It may be possible to complement our workflow with already existing techniques for these. This is, however, still a matter of research.
Probabilistic and Deterministic Methods: Applicability in Unconventional Reservoirs
Authors: Coll C. , Elliott S.
Published: June 2013

Unconventional resources are pervasive throughout large areas and are not affected by hydrodynamic forces. In contrast with conventional reservoirs, the discovery risk is typically low with reservoir boundaries typically extending beyond the limits of the acreage holding. When estimating reserves and resources, the major uncertainty in unconventional reservoirs tends to be around the local reservoir properties that control well production potential and ultimate recovery. Very high areal variability of factors such as permeability, well deliverability, saturation state, rock mechanical properties exists. Accordingly, field appraisal is continuous as the field is developed to help understanding reservoir heterogeneity dictates the initial production from the wells and decline rates. Technological advances help optimizing the mechanical efficiency of well operations improving the economic viability of these resources through increases in well rates and ultimate recoverable volumes accessed by each well as demonstrated by the successful implementation of new fraccing technologies in shale gas reservoirs.

The new SEC1 rules adopted in 2009 allow the application of probabilistic methods for reserves and resources estimations. In unconventional reservoirs different stages of maturity exist as described by SPE PRMS2, COGEH3 and SPEE4 Monograph 3 guidelines. The COGEH guidelines are based on deterministic methods whereas SPEE Monograph 3 guidelines are mainly focused on probabilistic methodologies to use for reporting reserves in resource plays (CSG, Shale, Tight Gas/Oil and Basin-centered Gas Systems) particularly how to estimate proved undeveloped reserves in areas where enough drilling and production exist. COGEH3 (volume 3) provides valuable guidance on deterministic estimation of reserves and resources for coal bed methane (CBM) and Bitumen/SAGD consistent with the definitions provided in COGEH Volumes 1 and 2. In November 2011 the new Guidelines for Application of the Petroleum Resources Management System were published by the SPE5. These new guidelines used the 2001 original guidelines as the starting point updating significantly two new areas: "Estimation of Petroleum Resources Using Deterministic Procedures" and Unconventional Resources. The 2011 SPE guidelines cover more extensively unconventional reservoirs describing the reservoir characteristics, extraction and processing methods, assessment methods, commercial and classification issues for heavy oil, bitumen, tight gas formations, coalbed methane, shale gas, oil shale and gas hydrates. This paper provides some guidance on best practices on the applicability of deterministic and probabilistic methods to estimate reserves and resources for unconventional reservoirs based on the maturity of the resource play and existing industry guidelines.
An Adaptive Evolutionary Algorithm for History-Matching
Authors: Abdollahzadeh Asaad , Christie Mike , Corne David , Davies Brian , Elliott Michael
Published: June 2013

Efficient history matching of highly uncertain reservoir models is important in many applications of the reservoir engineering area, such as reservoir management, production prediction, and development optimisation. History matching has commonly been done manually by a tedious trial and error approach in which global and local adjustments are done to the model properties until a best model is obtained which honours production response of the reservoir model. With recent advances in computer science and hardware, assisted history matching techniques can improve the quality of the match within less time and effort.

Stochastic evolutionary algorithms are popular methods in history matching and have been widely used to explore and search the global parameter search space and find multiple good fitting models. They are quite easy to implement, and if well applied, able to be globally convergent even in complex problems such as history matching. General critiques of these algorithms include high computational demands and demand for the tuning of the algorithm’s control parameters. Adaptation methods for EAs adjust algorithm’s control parameters during the evolution to improve the search quality and accelerate the convergence by guiding search toward appropriate regions of the search space. This insures a balance between exploration and exploitation properties of the algorithm.

In this paper, we introduce a novel adaptive scheme for EAs, which intelligently adapts the control parameter that affects the diversity of the population. The adapted control parameter is number of selected to generated solutions in each generation, which controls the balance between exploration and exploitation. We apply proposed algorithm to optimisation problem of two test functions and history matching problem of a well-known synthetic reservoir simulation model. Our results show that, compared with the original EAs, adaptive EA is able to find better spread of fitting models with better convergence to the minimum misfit, thus more effective and efficient history matching is achieved.
Reservoir Scale permeability Prediction Using Advanced Modeling Techniques - Application to Turbidite Reservoirs
Authors: Baggio Sylvie , Sirju Clive , Adaszkiewicz Monika , Pritchard Tim , Lovell Mike , Davies Sarah
Published: June 2013

Log derived permeability averages in homogeneous clastic reservoirs most often matches the reservoir scale permeability determined from well testing. However, when it comes to heterolithic, anisotropic reservoirs such as observed in successions interpreted as turbidites, there can be significant differences between reservoir scale estimates and traditional techniques such as arithmetic and geometric averaging. This mismatch is often overlooked, although it can be critical when it comes to history matching production data. The fundamental flaw of the log-only approach is that it assumes permeability to be isotropic, and therefore ignores the three-dimensional nature of permeability. In heterogeneous clastic reservoirs, the anisotropies originating from various small scale sedimentary structures may have an influence on fluid flow at larger scales, impacting the observed reservoir-scale permeability.

This paper demonstrates how data acquired from wireline logs and cores from very heterogeneous successions like turbidites may be used to consistently predict the reservoir scale permeability. The workflow consists in processing and integrating the data into a lamina-scale near-wellbore model containing structural as well as petrophysical properties; a flow-based upscaling method is then applied to provide a geologically consistent input into a single-well model, from which a typical well test scenario will be simulated; the resulting pressure transient is then analyzed to determine a simulated permeability-thickness product.

Presented in this paper is an application to two wells intersecting a turbidite reservoir. This shows that the permeability obtained from this workflow is closer to the well test permeability when compared to log derived estimates from traditional averaging techniques.

This method can be applied to obtain valid reservoir-scale permeability values that can then be compared to the actual well test result. However, it can also be applied in cases where the value of information processes prove well testing to be uneconomical; then, a global reservoir permeability value can still be obtained using the workflow described.
Seismic History Matching with Saturation Indicators Combined with Multiple Objective Function Optimization
Authors: Stephen Karl D.
Published: June 2013

Time-lapse seismic data offers additional information about the reservoir which can be used in history matching. Observed seismic data is often available as a relative measure of pressure and saturation changes and it can be difficult to compare directly to modelled data. Usually we need to calibrate the observed data or otherwise scale it for use in the misfit function. An alternative is to use a qualitative measure but this means that the production and seismic misfits can no longer be compared quantitatively. In this paper to solve this we examine the use of multiple objective functions to find better models that match the data.

We use a qualitative measure of the change of acoustic impedance in both the model and observed data domains to determine how much change takes places during production. Then we compare regions of change as a measure of similarity. With production data we use a conventional sum of squares misfit. A stochastic algorithm is used to find the best solutions. We modify the neighbourhood algorithm so that we accept models that will best fit either seismic or production misfits in a multi-objective fashion.

We demonstrate the approach on a synthetic model where the answer is known. We compare the results using a more conventional sum of squares misfit with one which uses multiple objective functions. We show that both the NA finds a better set of solutions that match both sets of observed datasets. We quantify the speed at which this occurs.

History matching with time-lapse seismic data adds additional constraints to conventional approaches with just production data. Models better reflect observations and are more reliable for forecasting. This leads to better decision making and planning in reservoir development.
Observed Spatial Statistics of Permeability and the Effects on Fluid Flow: are we Getting it Right?
Authors: Xiao-Qian Lin , Stephen Karl , Steele Richard
Published: June 2013

In geocellular modeling, the variogram is used to represent the spatial correlation of rock properties. Horizontal variograms are often assumed rather than measured due to the scarcity of subsurface data. Wells are drilled kilometers apart while reservoir heterogeneity occurs at much smaller scales. The use of outcrop data as analogues has therefore been widely practiced by geoscientists to supplement the estimation of horizontal variograms. Through research of reported observations from outcrop, this paper will reveal that the strategy used to define sampling intervals and data density in published outcrop studies can vary significantly with implications for modelling and simulation.

The impact on experimental variogram calculation has not been given sufficient attention and there is large variation, and hence uncertainty, on any variogram data used in modelling. We examine the choice of sampling interval and sufficiency on the derived variogram properties via a synthetic study. We also investigate the uncertainty of variograms used in modelling on flow simulation.

A number of models have been created to represent the range of variability in the spatial correlation of permeability reported in outcrop studies. The models were sampled with various intervals and amounts of data to create experimental variograms. We find that insufficient density of data can lead to variograms that may be misinterpreted leading to an incorrect choice of variogram range in subsequent modelling. From flow simulations we show how this is critical and that over- or under-estimation of the range can vary recovery factors by ten per cent.

Reservoir modelling and simulation is important for field management. A proper representation of the subsurface rock properties such as permeability is crucial so that accurate predictions and forecasts can be made. The most appropriate choice of semi-variogram parameters will therefore have a strong impact on reliability of models leading to more effective decision making.
High-Resolution Reservoir Modeling Using Image Fusion Technique in History Matching Problems
Authors: Sayyafzadeh Mohammad , Haghighi Manouchehr
Published: June 2013

History matching is an inseparable part of reservoir modelling in which flow performance data are incorporated into geological model to reduce uncertainty in decision making. Although, thus far numerous studies have been published in order to augment the quality of history matching, a comprehensive approach is not being taken toward it, and development in different steps of history matching, including reparameterization and optimization, is looked for. Reparameterization is used to reduce the number of decision variables and subsequently the degree of calibration freedom in order to expedite history matching procedure. But, it always brings reparameterization error into the problem.

In this study, an inventive algorithm is introduced in which reparameterization is unnecessary and accordingly the corresponding error is eliminated. In this algorithm, entire uncertain parameters including porosity and permeability distributions can directly be adjusted. Image fusion technique is widely used in image processing problems. Image fusion is a technique for combining a number of images into a single image to afford a more informative image. In this study, image fusion technique is applied in history matching problems. In the designed algorithm, different models intelligently and stochastically are merged based on their corresponding fitness values to produce a fitting model. It is a repetitive approach until stopping criteria are met. Hence, it performs similar to evolutionary algorithms while image fusion works as a mating operator.

In order to assess the proposed algorithm, the outcomes of history matching using this algorithm on a synthetic model and also PUNQ-S3 reservoir model are compared with a number of history matching approaches. The outcomes demonstrate an improvement over the applied approaches in terms of the quality of the history matched models.

The proposed approach is coped with a significantly larger number of variables, and accordingly high resolution history matched models are achieved. Also, the algorithm has an acceptable speed of convergence even in comparison with variable metric algorithms.
Computational Methodology to Study Heterogeneities in Petroleum Reservoirs
Authors: Cevolani J. T. , Mostafa A. E. , Vital E. A. , de Oliveira L. Costa , da Fonseca L. Goliatt , Sousa M. Costa
Published: June 2013

Characterization of hydrocarbon reservoirs is strategically important to define the productivity of oil and/or gas fields. It involves many challenges such as appropriate identification, classification and interpretation of diagenetic processes that directly affect the quality of the reservoirs. Proper studies demand integration and analysis of very large amounts of data, usually presenting high-dimensional feature spaces. Current methods have many manual steps leading to a limited exploration of the data. These challenges are being intensified due to the need of knowledge and time dedication from experts. We developed a novel methodology that combines established techniques, such as Principle Component Analysis (PCA), clustering methods, parallel coordinates and scatter plots, with features such as dynamic (magic) lenses – filter and shadow lenses –, axes reordering and color maps, to automatically perform reservoir characterization in order to assist the identification, validation and interpretation of petrofacies. Petrofacies is a set of petrographic characteristics of microscopic order which allow the analyst to understand the diagenetic processes, aiding in the evaluation of the potential for hydrocarbon storage in the reservoir. We have applied our methodology on several databases from different sedimentary basins – Espirito Santo and Parana basins (Brazil), Talara Basin (Peru) and Niger Delta Basin (Nigeria). We conclude that our method allows the analyst to gain insights about the entire database in a manner that is faster than the analysis using a manual method. It also allows validation of the results because it is a powerful tool that can qualitatively and quantitatively support the analyst in the identification, interpretation and validation of petrofacies. This new methodology can optimize data analysis of similar databases, accelerating the analysis and reducing the committed work by the experts.
Some Case Studies of Temperature and Pressure Transient Analysis in Horizontal, Multi-zone, Intelligent Wells
Authors: Muradov Khafiz , Davies David
Published: June 2013

Accurate measurement of real-time temperature and pressure across the well completion interval(s) has become standard in the modern production and injection wells. The data is used for routine production/injection monitoring, well stimulation, enhanced recovery operations, etc. During the last decade both the number of wells permanently equipped with pressure and temperature gauges as well as the accuracy and sensitivity of the sensors has increased dramatically. Large volumes of data are now produced that is often not "mined" for all the embedded information. Moreover, technology developments are exacerbating this data management problem with the availability of ever more reliable sensors at a lower cost, let alone the development of more advanced sensors capable of measuring additional properties of the flowing fluid.

The ambition of the Digital Oilfield is to provide continuous optimisation of field production by real-time, well control and monitoring. However, the actual level of use made of these large volumes of data is still low.

Downhole temperature measurements are able to provide extensive information for supporting well production diagnostics and optimisation. Recent publications have demonstrated that transient temperature analysis (TTA) has a high information potential with the unique advantage of being able to quantify zonal in- or out-flow. This derives from TTA being less affected by wellbore storage effects while at the same time providing a distinctive "build-up" or "draw-down" response to the performance of an individual reservoir layer. This latter has proven to be a highly productive source of zonal well production information, either as a stand-alone data source or in combination with pressure measurements, across the production interval(s).

This paper will present examples of pressure and temperature transient analysis of downhole data from a real, multi-zone, intelligent well. It will discuss the qualitative aspects of sandface and wellbore pressure and temperature response along with their quantitative analysis to provide zonal, multi-phase flow rate allocation.

The paper will provide novel insights into downhole data analysis for a horizontal well producing from multiple intervals. They can be applied to quantitatively interpret either discrete or distributed temperature data, both with and without accompanying pressure measurements. Application of the workflow proposed here can immediately increase the "Added value" derived from intelligent well technology.
Spatial Constraints for the Stochastic Modeling of Fault Networks in the Presence of Large Structural Uncertainties
Authors: Julio Charline , Caumon Guillaume
Published: June 2013

Faults greatly impact the heterogeneities, the fluid flow and the geomechanical behavior of hydrocarbon reservoirs. However, significant uncertainty affects fault location, extent and connectivity due to limited quality and lack of subsurface data. In contrast to the standard practice of reservoir modeling which tends to represent only one deterministic fault network, we propose to sample structural uncertainty about fault networks (both geometrical and topological) by simulating a set of possible models all constrained by subsurface data. The conditioning of the faults may be done from fault sticks interpreted from 2D or 3D seismic surveys. Fault sticks correspond to one interpretation and must be used carefully especially when the uncertainties on the fault position are high. The objective of this paper is to introduce a new method to constrain the stochastic simulation of seismic-scale faults by negative constraints which condition the non-occurrence of fault.

We propose to divide the simulation space into two subspaces: (1) a volume where the simulation of faults is allowed and (2) a volume where the occurrence of faults is excluded. These two volumes are separated by a closed surface, named envelope, used to constrain the position of faults. During stochastic fault simulation, we optimize the geometrical fault parameters (position of the center, dip, strike) so as to minimize a misfit function. The efficiency of this conditioning approach is tested on synthetic data sets.

The described simulation method is applied in the cases of large-scale and high uncertainties which can be characterized by the envelope delimiting the exclusion zones. The algorithm simulates faults which honor both statistical input parameters and exclusion constraints. The high uncertainties lead to the simulation of various fault networks with different geometries and topologies.

In the petroleum industry, the stochastic approach is widely used to manage the facies and petrophysical property uncertainties, but it is rarely applied to fault network modeling. The presented optimization algorithm belongs to data conditioning methods for stochastic fault simulation, with the distinctive feature to be adapted to dense and continuous data. The fault-exclusion zone is adequate to represent the continuous structural information recorded by the seismic data.
Produced Water Chemistry History Matching in the Janice Field
Authors: Vazquez O. , Young C. , Demyanov V. , Arnold D. , Fisher A. , MacMillan A. , Christie Mike
Published: June 2013

Produced Water Chemistry data (PWC) is the main source of information to monitor scale precipitation in oil field operations. Chloride concentration is used in order to evaluate the seawater fraction of the total produced water per producing well and is included as an extra history matching constraint to revaluate a good conventionally history matched reservoir model for the Janice field. Generally PWC is not included in conventional history matching and this approach shows the value of considering the nature of the seawater injection front and the associated brine mixing between the distinctive formation water and injected seawater.

Adding the extra constraint resulted in the re-conceptualization of the reservoir geology between a key injector and two producers. The transmissibility of a shale layer is locally modified within a range of geologically consistent values. Also, a major lineament is identified which is interpreted as a NW-SE trending fault, whereby the zero transmissibility of a secondary shale in the Middle Fulmar is locally adjusted to allow cross-flow. Both uncertainties are consistent with the complex faulting known to exist in the region of the targeted wells. Other uncertainties that were carried forward to the assisted history matching phase included: water allocation to the major seawater injectors; thermal fracture orientation of injectors and the vertical and horizontal permeability ratio (kv/kh) of the Fulmar formation.

Finally, a Stochastic Particle Swarm Optimization (PSO) algorithm is used to generate an ensemble of history matched (HM) models using seawater fraction as an extra constraint in the misfit definition. Use of addition data in history matching has improved the original good history matched solution. Field Oil Production Rate is interpreted as improved over a key period and although no obvious improvement was observed in Field Water Production Rate, Seawater fraction in a number of wells was improved.
Polymer Solution Injection – Near Wellbore Dynamics and Displacement Efficiency, Pilot Test Results, Matzen Field, Austria
Authors: Clemens Torsten , Deckers Marie , Kornberger Martin , Gumpenberger Thomas , Zechner Markus
Published: June 2013

A number of reservoirs in the Vienna Basin in Austria might benefit from polymer solution injection. In November 2011, a Polyacrylamide polymer injection pilot commenced for the 8th Torton Horizon reservoir to reduce the uncertainties related to this technology.

To further improve the understanding of the polymer solution injection, laboratory experiments and numerical simulations were performed.

The results of the injection test and laboratory experiments show that two phases can be distinguished: first, a phase of polymer solution injection below the Formation Parting Pressure (FPP) can be observed. This phase is characterised by high flow velocities in the near-wellbore area, resulting in severe degradation of the polymer, and a slower rise of the pressure than expected for undegraded polymers. In the second phase, the FPP is reached and fractures are generated. In this phase, the polymer solution exhibits shear-thinning behaviour in the fractures. Owing to significantly lower flow velocities in the formation, degradation of the polymers is limited. Phase one is usually short in comparison to phase two.

To achieve sufficient polymer solution injection rates for an economic project without degrading the polyacrylamide polymer, inducing fractures by injection is required for the reservoirs in the Vienna Basin. Hence, screening of fields has to include geomechanical properties of the reservoir sands and surrounding shales. Also, the risk of fracturing outside of the formation has to be assessed. In addition, the values of the FPP of the reservoir sands and surrounding shales and the direction of induced fractures should be determined. Furthermore, the injection water quality in terms of fines and oil content has an impact on the fracture growth and should be evaluated.
Cyclic Hysteresis of Three-Phase Relative Permeability Curves Applicable to WAG Injection under Low Gas/Oil IFT: Effect of Immobile Water Saturation, Injection Scenario and Rock Permeability
Authors: Fatemi S. Mobeen , Sohrabi Mehran
Published: June 2013

One major problem in the numerical simulation of the water-alternating-gas (WAG) process is the uncertainty associated with the changes in three-phase relative permeability (kr) values in the sequence of drainage and imbibition cycles known as cyclic hysteresis. In this work we have investigated the effect of cyclic injection of water and gas on three-phase kr of water, gas and oil under both water-wet and mixed-wet conditions. Two different sandstone cores with one order of magnitude difference in absolute permeability (65 mD and 1000 mD) have been used in the coreflood experiments.

In the base study, WAG injection started with water flooding (I) followed by gas injection (D) and this cyclic injection was repeated three times (IDIDID). To investigate the effect of immobile water saturation, the IDIDID injection scenario was repeated with lower immobile water saturation. To study the effect of saturation history, another WAG experiment was performed which started with the primary gas flooding (D) followed by water injection (I) and this cyclic injection were repeated as DIDIDIDI. For all of the experiments, three-phase relative permeabilities were obtained analytically from the coreflood data using an extension of Buckley-Leveret formula to three-phase flow.

The results show irreversible kr hysteresis loops for water and gas and saturation history dependency for oil in processes involving cyclic injection under three-phase flow conditions. Generally, krg reduced during successive cycles for all WAG experiments. For the IDIDID injection sequence and in water-wet system, it was found that krg shows larger hysteresis effect for the case with higher immobile water saturation. krw hysteresis was larger in the DIDIDIDI injection scenario compared to the IDIDID case. krg and krw hysteresis effects were larger for the 1000 mD core compared to the low permeability (65 mD) sample. The most important hysteresis effect for both krg and krw was observed for the transition from two-phase to three-phase. As WAG cycles were repeated, krg and krw hysteresis reduced became minimal after the 2nd water injection in IDIDID and 2nd gas injection in DIDIDIDI injection sequences.

Comparison of our experimental observations with predication of existing models highlights some serious shortcomings of reservoir simulators in simulation of oil recovery processes involving three-phase flow and flow reversal. The paper also offers some novel insights into cyclic hysteresis behaviour and offers explanations based of our understanding of the pore-scale and core-scale displacement mechanisms involved in three-phase flow and WAG injection.
Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated with H2S into Depleted Gas Fields in Northeast Netherlands
Authors: Bolourinejad P. , Herber M. A.
Published: June 2013

Depleted gas fields are amongst the most probable candidates for subsurface storage of CO2. With proven reservoir and qualified seal these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine due to formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and cap-rock. Thus, for adequate, safe and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. In order to investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30 days) laboratory experiments on reservoir and cap-rock core samples from gas fields in northeast Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream (H2S) in these fields.

The injected gases were CO2, CO2+100 ppm H2S and CO2+5000 ppm H2S. Before and after the experiments the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. Also the permeability of the samples was measured. Following the experiments, dissolution of feldspars, carbonates and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S in the CO2 stream. Firstly we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection where dissolution of anhydrite was dominant in the samples. Secondly, severe salt precipitation took place in the presence of H2S. This is caused by the higher solubility of H2S in water and a higher water content of gas phase in the presence of H2S. This was confirmed by modeling using CMG-GEM (CMG, 2011) modeling software.

The precipitation of salt, anhydrite and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and <3%, respectively. In caprock samples permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5000 ppm H2S the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, salt precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.
Studies and Pilot Project on Steam Stimulation with Multiple Fluids for Offshore Heavy Oil Reservoirs
Authors: Xu Wenjiang , Chen Zhangxing , Shan Jincheng , Sun Yongtao
Published: June 2013

Steam flooding and stimulation processes have proven to be the most promising method for commercial in situ recovery of heavy oil. For high quality and thick oil reservoirs, these processes can achieve oil recovery of over 30% OOIP. However, for thin, deep and offshore oil reservoirs, they are uneconomic due to excessive heat loss to overburden and great requirement to heat the reservoir rock.

A new process, Steam and Multiple Fluids (SMF), is being developed to improve efficiency of the steam stimulation process for offshore heavy oil reservoirs. It involves the addition of non-condensable gases to the injected steam. Injected gases accumulate in the region away from the well and lower the temperature. Only the region’s temperature near the well is close to the temperature of steam. Heat loss to the overburden and the heat requirement to heat reservoir rock can be significantly reduced due to the lower temperature requirement. Considerable saving can be achieved from reduction in quantity of steam required for the process.

This process is studied by using laboratory experiments and numerical simulations via a 3D thermal model for an offshore heavy oilfield. The results show that, compared to the cold production and standard steam stimulation processes, the oil rate from SMF is the highest. The application of this process makes production of offshore heavy oil economic and should extend the range of reservoirs that can be produced economically. A pilot test for calibrating this new process is reported.