bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of solid pyrolysis products on selected soil properties in a laboratory experiment
Authors: Gulyás Miklós , Fuchs Márta , Rétháti Gabriella , Holes Annamária , Varga Zsolt , Kocsis István , Füleky György
Published: May 2015

Csontszénnel és növényi eredetű bioszénnel tenyészedényes modellkísérletet állítottunk be, hogy feltárjuk a kiválasztott magyarországi talaj fizikai és kémiai tulajdonságaira gyakorolt hatásokat. A tenyészedényes modellkísérletben a kezeléseknek megfelelően (0, 1, 2,5, 5 és 10%) 500 cm3-es műanyag edényekbe 200 g talajkeveréket tettünk. Vizsgáltuk a minták AL-oldható P- és K-tartalmát, vízoldható összes sótartalmát, desztillált vizes pH-ját, kötöttségét és szerves-C-tartalmát (Tyurin módszerével).A kísérlet eredményeképpen megállapítható, hogy a csontszén (ABC) bekeverés hatására jelentősen megnőtt az AL-oldható P2O5-tartalom a talajkeverékekben, köszönhetően a csontszén eredendően nagy P-tartalmának.A pH és az összes sótartalom jelentősen nőtt a csontszén (ABC) kezeléseket követően, elsősorban a csontszén nagy ásványianyag-tartalma miatt. A növényi eredetű bioszén (BC) kezelések esetében azonban pH-növekedés csak a nagyobb koncentrációnál volt tapasztalható, az összes sótartalomban pedig nem tapasztaltunk változást. A sótartalom- és pH-növekedés egyik kezelés során sem okozott túlzott sófelhalmozódást. A sótartalom 0,07% körül alakult a legnagyobb dózis esetében is, azonban hosszú távon érdemes figyelmi a sótartalom változását.A növényi eredetű bioszén (BC) bekeverése növelte a kezelt talaj víztartó képességét, kálium- és szerves-szén-tartalmát, míg a csontszén esetében nem tapasztaltunk hasonló hatást. További kutatások szükségesek, hogy újabb információkat kapjunk a bioszenek mezőgazdasági felhasználásáról. Fokozottan igaz ez a csontszénre, mivel a jövőben a foszforutánpótlás alternatívája lehet.
Model experiments on the physical properties of soil contaminated with red mud
Authors: Makó András , Anton Attila , Csitári Gábor , Rékási Márk , Uzinger Nikolett , Barna Gyöngyi , Széplábi Gábor , Hernádi Hilda
Published: May 2015

Vizsgálatsorozatunkban a vörösiszap-elöntés hosszabb távú talajtani hatásait vizsgáltuk a szennyezett terület mellől kontrollként vett talajmintákból készített talajoszlopokon. Két különböző szcenáriót modelleztünk. Az elsőben a vörösiszaptározóból közvetlenül kiömlő, nagy víztartalmú, erősen lúgos (∼ pH 13) vörösiszapszuszpenzió talajtani hatását tanulmányoztuk, míg a második esetben a „vörösiszapár” levonulása után a talajfelszínen kiülepedett vörösiszap-öntésanyag hosszabb távú talajfizikai, -kémiai és -biológiai hatásait vizsgáltuk (30, 60 és 120 napos vörösiszap-borítás mellett). Az oszlopkísérlethez használt talajminták egy vörösiszappal nem szennyezett szántóföldi területen feltárt humuszos öntéstalaj különböző genetikus szintjeiből származtak.Közleményünkben a vörösiszap-elöntés talajtani hatásait vizsgáló modell oszlopkísérleteink talajfizikai vonatkozású eredményeit foglaltuk össze. Megállapítottuk, hogy a lúgos kémhatású, nagy Na+-tartalmú iszapból a talajba szivárgó oldatok jelentősen átalakították a vizsgált talaj szerkezetét: a felső talajrétegekben szerkezetleromlást (aggregátumstabilitás-csökkenést) okoztak, míg az alsóbb szintekben (feltételezhetően a bemosódott vagy helyben keletkezett nátrium-szilikát ásványok ragasztó hatása miatt) ideiglenesen aggregátumstabilitás-növekedést tapasztaltunk.Vizsgálati eredményeink alapján megállapítható, hogy a vörösiszap-borítás hatására a talajok elemi szemcséinek méret szerinti megoszlásában mérhető arányeltolódások — a vörösiszap-szemcsék felszíni rétegekbe történő bemosódásán túl — a fenti talajszerkezet-változási folyamatokkal függhetnek össze.
Effect of forest plantations on subsurface salt accumulation in lowlands with shallow groundwater
Authors: Balog Kitti , Gribovszki Zoltán , Szabó András , Jobbágy Esteban , Nosetto Marcelo , Kuti László , Pásztor László , Tóth Tibor
Published: May 2015

Az alföldi üledékes síkságon, szubhumid klímán a füves területek és szántók helyén telepített erdők erőteljes hatást gyakorolnak a talajtani közegre, a talajvíztükör szintjére és mozgására. A fák mély gyökerezése és a korábbi vegetációnál jelentősen nagyobb vízfelvétele elősegíti a sótartalom-növekedést az altalajban, illetve a talajvízszint-csökkenést. Az erdőtelepítés globális szinten ugrásszerűen megnövekedett, Magyarországon az erdők területének növekedése elérte az évi 15.000 ha-os rátát. A telepítések főleg az Alföldet érintették, ahol az erdők részben sekély talajvizű területek gyepeit és szántóit váltották fel.Kutatásunk során alföldszerte 31 erdő-kontroll furatpár esetében talajtani, hidrológiai és biológiai terepi megfigyeléseket végeztünk, beleértve a megütött talajvízszint észlelést, a talajvíz sótartalom vizsgálatát, a földtani közeg rétegződésének leírását és a fafaj, valamint az állomány korának rögzítését. Ezen kívül talajvízszint megfigyelő kúthálózatot telepítettünk és laboratóriumban vizsgáltuk a talaj és talajvíz kémiai sajátosságait.A telepített erdők esetében a biomassza pozitív összefüggést mutatott a talaj sófelhalmozódásának mértékével, amit a fafaj (nyár > tölgy > akác) és az állománykor befolyásolt. A három vizsgált fafaj között megmutatkozó különbségek a fák eltérő növekedési erélyével és párologtatásával mutatnak összefüggést.Hazánkban a téli időszakban megfigyelhető, lefelé irányuló mély csapadékbeszivárgás a sók kimosódását eredményezi, így a sófelhalmozódás mértéke kisebb volt a talajban, mint a vizsgált, hasonló környezeti feltételekkel, de melegebb klímával rendelkező argentin pampa területeken.
Fertilizer effects in a triticale monoculture on sandy soil
Authors: Kádár Imre , Ragályi Péter
Published: May 2015

Az MTA ATK TAKI Őrbottyáni Kísérleti Telepén karbonátos homoktalajon beállított NPK műtrágyázási tartamkísérlet 36–43. évében, 2006 és 2013 között vizsgáltuk a műtrágyázás hatását a tritikále fejlődésére, termésére és elemfelvételére. A termőhely talaja a főbb tápelemekben (N, P, K) gyengén ellátott, a szántott réteg 1% körüli CaCO3-ot és 1% humuszt tartalmaz. Az altalaj erősen karbonátos, az agyagos rész 5–10%. A talajvíz 8–10 m mélyen található, a terület aszályérzékeny. Évente a P- (0, 60, 120 kg P2O5·ha−1) és K-műtrágyákat (0, 100, 200, 300, 400 kg K2O·ha−1) ősszel szántás előtt, valamint a N (0, 80, 160 kg N·ha−1) felét ősszel, a másik felét tavasszal szórtuk ki 25%-os pétisó, 18%-os szuperfoszfát és 50%-os kálisó formájában. A kísérletből levonható főbb tanulságok:

Talajgazdagító PK-műtrágyázás eredményeképpen a kontrolltalaj igen gyenge PK-ellátottsága a kielégítő 150–200 mg·kg−1 NH4-acetát+EDTA-oldható tartományba emelkedett a kísérlet 41. évében (2011-ben). A szuperfoszfáttal végzett trágyázás eredményeképpen igazolhatóan nőtt a feltalaj oldható S- és Sr-tartalma, mely az alkalmazott hazai Kóla-alapú/nyersanyagú eredetre vezethető vissza. A hazai szuperfoszfátok 18–22% körüli elemi Ca-, 13% S-, 7–8% P-, 1–2% Srkészlettel rendelkeztek.

Nemcsak a homoktalaj rendkívül heterogén, hanem a rajta fejlődő termés mennyisége is extrém szórásokat mutatott. Az évek és kezelések között egy nagyságrendet elérő különbségek adódtak. Az évek átlagait tekintve ötszörös eltéréseket tapasztaltunk. Az „évhatások” kifejezettek voltak. Termésdepresszió léphet fel egyaránt az aszály/vízhiány és a túlbő csapadék fennállása esetén.

A P-kínálattal nőtt a növényi részek P-, Mn- és Sr-készlete, míg a beépült Znmennyiség visszaesett. Fellépett a P-Mn szinergizmus, illetve a P-Zn antagonizmus. A Mo-koncentráció a növekvő NPK-műtrágyázással a szalmában 1/3-ára, a szemtermésben a felére zuhant.

A vizsgált nyolc év alapján még nem ítélhető meg, hogy a tritikále mennyire alkalmas a monokultúrás termesztésre, de összevetve a telepen 52 éves ún. „örökrozs” kísérletünkkel, ez lehetővé válhat a jövőben.
Gyógyszerkölcsönhatások kiszűrésére szolgáló adatbázisok értékelése: ellentmondások és egyezőségek
Authors: Somogyi-Végh Anna , Nyaka Bernadett , Vida Róbert György , Lovász Andrea , Botz Lajos
Published: May 2015

Introduction: Recognition of potentially harmful drug interactions is one of the duties of healthcare. However, solutions involving databases are fraught with contradictions due to the lack of standardized principles and data. Aim: The aims of the authors were to perform a comparative evaluation of Hungarian and international databases and to explore ambiguities and contradictions in order to develop more standardized criteria for screening interactions. Method: Four Hungarian and two English-language websites and software, and the summaries of product characteristics were compared. The authors analyzed 40 drug–drug and 8 drug–supplement interactions and looked at 8 cases, which represent 28 pairs of interacting substances. Results: The databases warn about most interactions, but these warnings were rarely helpful in preventing undesired consequences. The authors found discrepancies between the databases in 70% of interactions. When looking at different products with the same active ingredients, discrepancies cropped up in 0–66.7% of the cases. Up to 80% of searches for supplementary product interactions did not produce satisfactory results. Conclusions: In the present situation mapping these ambiguities and creating a standardized classification system would be advantageous. Orv. Hetil., 2015, 156(18), 720–730.
DEM modelling of a jointed rock beam with emphasis on interface properties
Authors: Boon C. W. , Houlsby G. T. , Utili S.
Published: May 2015

This paper compares analyses performed via the distinct element method (DEM), employing rigid blocks and compliant joints, with results using finite-difference software (FLAC) obtained previously by other researchers. The paper then examines the capability of the rigid-block DEM at modelling joints realistically, with emphasis on the moment transfer between blocks. The line of thrust from this analysis was found to fit well with the well-established uniform catenary curve and the parabola, which has been used extensively in the rock engineering literature. This is an important verification exercise that is still lacking in the literature, especially for the rigid-block DEM. Finally, a comparison is made between the DEM and experimental work carried out previously by other researchers. The previously reported laboratory data were reinterpreted to derive more accurate contact laws in both normal and shear directions. A strain hardening or continuously yielding model was adopted in the latter. The calibration approach is demonstrated. The numerical findings suggest that improved predictions of beam deflections can be obtained and the predicted horizontal thrusts are comparable to the results obtained by FLAC.
Climate change impacts on renewable electricity generation
Authors: Cradden Lucy , Burnett Dougal , Agarwal Atul , Harrison Gareth
Published: May 2015

The generation of renewable energy is strongly related to climate and could be vulnerable as the climate changes in the coming decades. The assessment of the potential risks is a new and evolving area of science. In light of the rapid pace of development and more prominent contribution of renewables to UK electricity generation, this work presents a summary of the current state of knowledge in the field and highlights some of the critical parameters and areas of uncertainty. An assessment of potential changes in the levelised cost of energy is presented, with the caveat that this is entirely based on existing data, which in some cases are highly uncertain. The areas of critical research for both understanding climate and engineering for adaptation are discussed.
Dystrophin hydrophobic regions in the pathogenesis of Duchenne and Becker muscular dystrophies
Authors: Liang Yingyin , Chen Songlin , Zhu Jianzong , Zhou Xiangxue , Yang Chen , Yao Lu , Zhang Cheng
Published: May 2015

The aim of our study was to determine the role of dystrophin hydrophobic regions in the pathogenesis of Duchenne (DMD) and Becker (BMD) muscular dystrophies, by the Kyte-Doolittle scale mean hydrophobicity profile and 3D molecular models. A total of 1038 cases diagnosed with DMD or BMD with the in-frame mutation were collected in our hospital and the Leiden DMD information database in the period 2002-2013. Correlation between clinical types and genotypes were determined on the basis of these two sources. In addition, the Kyte-Doolittle scale mean hydrophobicity of dystrophin was analyzed using BioEdit software and the models of the hydrophobic domains of dystrophin were constructed. The presence of four hydrophobic regions is confirmed. They include the calponin homology CH2 domain on the actin-binding domain (ABD), spectrin-type repeat 16, hinge III and the EF Hand domain. The severe symptoms of DMD usually develop as a result of the mutational disruption in the hydrophobic regions I, II and IV of dystrophin – those that bind associated proteins of the dystrophin-glycoprotein complex (DGC). On the other hand, when the hydrophobic region III is deleted, the connection of the ordered repeat domains of the central rod domain remains intact, resulting in the less severe clinical presentation. We conclude that mutational changes in the structure of hydrophobic regions of dystrophin play an important role in the pathogenesis of DMD.
Density of Crude Oil Saturated With Carbon Dioxide
Authors: Marra R. K. , Poettmann F. H. , Thompson R. S.
Published: May 2015

A correlation for determining the density of carbon dioxide-crude oil mixtures with engineering accuracy was developed. The correlation is based on the ideal solution principle. Apparent liquid densities for carbon dioxide were correlated as a function of pseudo liquid system density and carbon dioxide concentration. In the final working correlation the pseudo liquid system density is expressed as a function of pseudo liquid hydrocarbon density and carbon dioxide concentration. The pseudo densities are then corrected to reservoir conditions. The correlation is presented in both graphical and equation form and is easily adaptable to computer or hand held calculator applications.

The mean error for the 154 data points used to develop the correlation is + 1.39 percent, the average absolute error is 4.46 percent, and the standard deviation is 5.25 percent. An error analysis of the experimental data indicated that when removing the 20 points having the greatest deviation the mean error is + 0.06 percent, the average absolute error is 2.8 percent, and the standard deviation is 2.44 percent.

A review of the existing literature on density calculations shows that the great majority of the correlations are based on the theorem of corresponding states. These methods yield accurate results. However, the equations were developed for pure substances and mixing rules must be applied for complex mixtures making the equations less accurate and more complicated. In addition, most of the equations were developed without the consideration of non-hydrocarbons such as CO2. Generally, when non-hydrocarbons are introduced the correlations become less accurate. The correlations were not checked against crude oils or crude oil mixtures containing non-hydrocarbons.

The correlation presented in this paper provides a simple method for calculating the density of carbon dioxide crude oil mixtures with engineering accuracy. The densities are used for calculating formation volume factor, swelling, and in other reservoir engineering calculations.
Use of Tracers To Investigate Drilling Fluid Invasion and Oil Flushing While Coring
Authors: Brown A. , Marriott F. T.
Published: May 2015

A procedure is described by which oil flushing during coring of steamed and unsteamed heavy oil formations can be estimated. Chemical tracers in the drilling mud are used to indicate if filtrate invasion is occurring. Core saturation analyses are coupled with data from high velocity corefloods and temperature-dependent residual oil saturation measurements to estimate oil flushing during coring.
The Impacts on Waterflood Management of Inducing Fractures in Injection Wells in the Prudhoe Bay Oil Field
Authors: Williams D. B. , Sherrard D. W. , Lin C. Y.
Published: May 2015

The induced fracturing of water injection wells in the Prudhoe Bay Oil Field has been of concern since original waterflood pilot tests were conducted in 1978. Early step-rate tests showed that, as a result of the injection of cold (80°F) seawater into the 200°F Ivishak reservoir, the formation fracture gradient was significantly reduced. Interest peaked with the need to develop a water-flood management strategy soon after waterflooding commenced in the second half of 1984.

In order to address the fracturing question, in-depth studies of field injection trends, innovative pressure transient analyses of step-rate data, interpretation of specially designed injection well tests, and several simulation studies were conducted. The results from these independent approaches provided definitive and confirming evidence on the extent of fracturing; this was a crucial prerequisite to the definition of a long-term injection strategy.

Subsequently, the impact of formation breakdown on areal and vertical sweep and on oil production rates was evaluated, and it has been concluded that potential negative effects of inducing fractures with clean water injection into the Ivishak formation are minimal, while benefits include accelerated oil production. As a result, an injection pressure limit above the thermally reduced formation fracture gradient has been defined and adopted.
Development of Reservoir Descriptions To Aid in Design of EOR Projects
Authors: Chopra A. K. , Stein M. H. , Ader J. C.
Published: May 2015

A new technique was developed to obtain reservoir descriptions to aid in the design of enhanced oil recovery (EOR) projects. This technique incorporates the reservoir performance during primary and secondary processes as well as the geological and petrophysical data. The advantage of this technique over statistical techniques is that a more realistic reservoir description can be obtained. The reservoir description when used with an EOR reservoir simulator would yield a more realistic prediction of EOR performance and minimize the risk in an EOR field project. This technique may also be used to validate a reservoir simulator for field scale EOR performance. If the reservoir description is derived independent of EOR performance, the reservoir description is based only on the reservoir heterogeneities. The EOR process variables can then be quantified from the EOR performance without changing the reservoir description (Ader and Stein1).

The application of this technique is illustrated for a 250 acre area of interest in a San Andres formation reservoir. The initial reservoir description is formulated based on permeability to porosity ratio plots, injection and production profiles, core data, and pressure transient tests. The initial gas saturations and pressures are obtained based on dimensionless performance curves. The reservoir description is then refined by history matching primary and secondary performance for individual wells using a reservoir simulator. For the example discussed in this paper, an excellent match of performance was achieved using this technique.
Laboratory Study of Foaming Surfactant for CO2 Mobility Control
Authors: Di Julio S. S. , Emanuel A. S.
Published: May 2015

The effectiveness of foam as a mobility control agent has been tested by an immiscible CO2 core-flood displacement of a California heavy oil (14°API). The study was conducted with a parallel coreflood system consisting of two segmented unconsolidated reservoir cores with a permeability ratio of 3.7. This represented a physical model of two noncommunicating reservoir sand layers of different permeabilities.

Two base case parallel corefloods were performed by simultaneously waterflooding both cores, then injecting water and CO2 alternately (WAG). Oil recoveries for the two base cases were: Oil Recovery (% OOIP)Low Permeability CoreHigh Permeability CoreWaterflood046.4CO2-WAG0.46.7

The CO2-WAG was followed by CO2-foam.

Foam was produced by adding 0.5 wt% surfactant to the brine solution and then simultaneously injecting the surfactant solution and CO2. The surfactant was Chevron Proprietary Surfactant CRSO 85/66, selected for the given reservoir fluids and rock.

Injection of foam into the parallel core system produced an incremental recovery of 19% OOIP from the high permeability core and 52% OOIP from the low permeability core. The total incremental oil recovery over waterflood for CO2 and foam injection was 40% OOIP.

Results of this parallel coreflood study have demonstrated three points: The ability of foam to reduce CO2 mobility, which resulted in the incremental oil recovery from the high permeability core; andThe ability of foam to divert CO2 to the low permeability core which showed little recovery from waterflood or CO2-WAG.The ability of foam to recover an incremental of 33.6% of OOIP of heavy oil over the water-flood and CO2-WAG.
Horizontal Well Pressure Analysis
Authors: Ozkan E. , Raghavan R. , Joshi S. D.
Published: May 2015

This paper presents an analysis of the pressure transient behavior of a horizontal well or a drainhole. The performance of horizontal wells and fully penetrating vertical fractures is compared. Dimensionless wellbore pressures are computed for two classical boundary conditions; namely infinite-conductivity and uniform-flux. Results are presented as pseudoskin factors and as type curves. In addition to conventional pressure versus time type curves, derivative type curves using pressure-time predictions are presented. The derivative approach we discuss here is new to the petroleum literature and is applicable to a broader range of problems than that considered here.

Computations suggest that horizontal well productivity is governed by two parameters: 1) the dimensionless well length, LD (LD=L/(2h)kz/k, where L is the length of the well, h is the formation thickness, and kz and k are the vertical and horizontal permeabilities, respectively), and 2) the dimensionless well radius, rwD, (the ratio of well radius to well half-length if the formation is assumed to be isotropic). Results indicate, that horizontal well productivity (infinite-conductivity) is almost identical to that of a fully penetrating vertical fracture of infinite-conductivity if the dimensionless horizontal well length, LD, is greater than 4.0. This result shows that horizontal wells may perform better than vertically fractured wells, if non-ideal aspects associated with vertically fractured wells such as limited conductivity or height, are taken into account.

Results have been obtained for LD in the range 0.1 ≤ LD ≤ 100 and dimensionless well radius, rwD, in the range 10−4 ≤ rwD ≤ 10−2; these ranges should encompass expected values of horizontal well length, reservoir height, and ratio of vertical and horizontal permeability. Pressure responses and pseudoskin factors are calculated for four different well locations within the productive interval. The pseudoskin factors are insensitive to well location.
Using Finite System Buildup Analysis To Investigate Fractured, Vugular, Stimulated, and Horizontal Wells
Authors: Mead H. N.
Published: May 2015

The Rectangular Hyperbolic Method (RHM) is a steady state, finite system concept which has proved to be amazingly accurate in determining final static reservoir pressure at time of shutin. The method also calculates slope, skin, percentage of open reservoir thickness contributing to flow, effective drainage radius and permeability. It apparently also gives reasonable answers in horizontal well buildups. It has been found that all wellbore reservoir pressure buildups after all wellbore and storage effects have died out follow a rectangular hyperbolic curve. The analysis is based solely upon Darcy's steady state radial flow equation, the basic transient pressure buildup equation and the determination of effective drainage radius from Mt/Uo in an empirical equation based upon field date obtained from the literature. RHM is not related to any method based upon an infinite system concept.
A Simulator for Drillstem Test Interpretation
Authors: Hegeman P. S. , Abbaszadeh M.
Published: May 2015

An analytical drillstem test (DST) simulator has been developed. The simulator can be used to verify the interpretation of drillstem tests with insufficient or poor quality flow rate data. Therefore, the immediate application of the simulator will be to improve the interpretation of drillstem tests that do not flow to the surface. A common example of such a test is a DST conducted on-land, open-hole, where rate measurement devices are rarely used because they are expensive relative to the cost of the test.

The simulator was designed to be consistent with the quality of pressure and rate (or fluid recovery) data measured on most non-surface flowing DST's. Although rate data may be inaccurate during flow periods, the measured pressures are usually reliable. Therefore, the DST is modeled as a sequence of alternating pressure-specified flow periods and rate-specified buildup periods. The interpretation is verified by comparing both simulated vs. measured pressures and fluid recoveries.

Using field data, it is shown that this simulator can be used to enhance the interpretation of non-surface flowing DST's.
New Methods for Estimating Parameters of Low Permeability Reservoirs
Authors: Kuchuk F. J.
Published: May 2015

The use of simultaneously measured downhole pressure and flow rate may not completely eliminate wellbore storage or afterflow effects when there is considerable additional wellbore volume below the pressure gauge and flowmeter. This paper presents new interpretation methods with or without measured wellbore flow rate, taking the additional wellbore volume into account. A diagnostic method is also presented for the determination of the correct logarithmic convolution straight line.

It is shown that a simple deconvolution (β-deconvolution) is possible when the wellbore flow rate increases (drawdown) or decreases (buildup) exponentially.

For partially penetrated wells, it is also shown that the vertical permeability can be obtained from either the onset of the semilog straight line if it evolves or the simultaneous use of the deconvolution and the convolution associated with non-linear estimation.

New solutions are presented for infinite-conductivity vertically fractured wells with wellbore storage (including the fracture storage, which may be important even if the flow rate is measured at the wellbore) and skin effects.

Two examples are presented to demonstrate the use of the new interpretation methods for both drawdown and buildup tests.
Hole Cleaning Performance of Water vs. Polymer-Based Fluids Under Turbulent Flow Conditions
Authors: Bizhani M.. , Rodriguez-Corredor F. E. , Kuru E..
Published: May 2015

The problem of solid cleanout in horizontal wellbores is studied experimentally. The special case of drilling fluid circulation with no inner pipe rotation is considered. This case is similar to Coiled tubing drilling where often hole cleanout must be performed. Sand sized cuttings (ranging from 260 micron to 1240 micron) are used. Critical velocity and wall shear stress required for initiating bed erosion are measured. Water and viscous polymer base fluids with 3 different polymer concentrations are used.

Results have shown that water always initiate cuttings movement at lower flow rates than polymer solutions. Fluids with higher polymer concentration and hence with higher viscosity required higher flow rates to start eroding the bed. Critical wall shear stress is also determined from pressure loss measurements. Analyzing the data revealed that water initiate cuttings removal at lower pressure loss than more viscous fluids. Higher viscosity fluids always showed higher pressure loss at the initiation of bed erosion.

For the range of cuttings size studied, results show that intermediate cuttings size is easier to remove. Smallest and largest cuttings are more difficult to move requiring higher flow rates and higher pressure losses.

Dimensionless analysis of relevant parameters to the process of cuttings movement is performed. It is shown that dimensionless wall shear stress (in the forms of Shield's stress and also ratio of shear velocity to settling velocity) correlates well with particles Reynolds number. Based on this finding two correlations are developed to predict wall shear stress required for initiating cuttings movement under different conditions.
Continuous Environmentally Efficient Pipeline Leak Detection
Authors: Rahmes Mark , Bingman Tasha , Blue Mark , Lemieux George
Published: May 2015

High-resolution sensors provide essential information to the oil and gas industry when planning for corridor right-of-way, land restoration, damage prevention, risk management and emergency response/damage prevention. The world's growing need for energy has put pressure on the remote sensing community to create even higher resolution and more accurate sensors than ever before. The location of the area of interest where remote sensing is needed is often based on the location of potential petroleum reserves. Political, terrain and weather conditions often determine the choice of technology used to collect the necessary data. Continuous pipeline monitoring is becoming increasingly critical for the oil and gas industry, which faces new challenges due to higher demands for energy. This paper presents the design, development and testing of a smart, wireless sensor network for early leak detection in oil pipelines, based on sensor measurements. Today's low power sensors are capable of measuring pressure, temperature and flow changes due to leaks. We describe a system model for determining decision-making strategies based upon the ability to perform data mining and pattern discovery by utilizing sensor information to detect leaks or abnormal situations. We discuss the development of a method for determining actionable information using game theory. We focus on applying probabilistic models to leak detection and geospatial tools for assisting emergency response and pipeline repairs. Probabilistic predictions are critical in practice on many decision-making applications. However, applicability to big data is complicated by the difficulties of inference in complex probabilistic models, and by computational constraints. Copyright 2015, Society of Petroleum Engineers
A Successful Post Completion Sand Control Method Used in Thermal Enhanced Oil Recovery Operations at the Kern River Field in Bakersfield, CA
Authors: Franks Spencer , Wise John , Rodriguez Sam , Hay Harold , Sanchez Fred , Ripley Mike , Erlendson Bill
Published: May 2015

The Kern River Field is one of the oldest continuous producing oil fields in North America. The field was originally discovered in 1899 and today comprises more than 10,000 active producing wells. The API gravity of oil in this field ranges between 11-13 degrees, and the operator employs thermal enhanced oil recovery methods in the form of continuous and cyclic steam (CS) injection. Rod pumping systems are the most common method of artificial lift utilized in this field. The most prevalent subsurface failure event realized by the operator is a sanded/seized (S/S) pump. More than fifty percent of all subsurface failures are associated with sand production. This paper will outline the use of resin injected during a cyclic steaming event (CS), down the casing annulus or tubing, in order to consolidate sand grains in the formation and reduce the potential for the influx of sand while a well is on production. In 2013 a project team was formed to pilot this sand control method at the Kern River Field. Candidates for this treatment were selected based on the frequency of sanded/seized events and reported wellbore integrity. Through this pilot, the project team was able to extend meantime between failure (MTBF) and achieve incremental oil production. The use of resin injected during a cyclic steaming event (CS) can improve well reliability and enhance well economics of marginal oil producers by providing an alternative to more expensive remedial options.
Remediation of Channeled Wells and Completions of Infill Wells by Using Resin-Coated Proppant and Proppant Coated with Special Resins in an Unconsolidated Sandstone Reservoir
Authors: Kruse Gustavo , Puliti Raúl , Millan Santiago Perez , Best Rocío Ortiz
Published: May 2015

19° API gravity oil with a viscosity between 150 to 200 cp is produced from the “El Corcobo Norte” and “Cerro Huanul” fields (550 active producer wells and 330 active injector wells) located in the Neuquen basin, Argentina. The reservoir is an unconsolidated sandstone reservoir that has been producing since 2005 by combining two techniques: cold heavy oil production with sand (CHOPS) and conventional waterflooding. Water injection began approximately one year after the start of production of oil, and while an excellent production response to the injection well was observed, the continuing sand production generated deep wormholes that allowed for direct communication between the injector and producer in some wells, resulting in the total loss of oil production.

Beginning in 2011, different remediation techniques were tested from the injector wells to repair the “pipeline” to the producing wells, with variable results. The original remediation program consisted of two steps: 1) a treatment to reconstitute the porous matrix (TRPM) and 2) a conformance water-control treatment (WCT), which was not as effective and was eliminated in the following remediation treatments. TRPM allowed the operator to put back into production wells that had been shut in, and its design evolved to help reduce costs and continue the wells’ reactivation.

To achieve an estimated ultimate recovery (EUR) factor of 50% (it was at 35% between the primary and secondary recovery), an injection project including an alkali, surfactant, and polymer (ASP fluid) treatment was implemented to improve the fluid sweep efficiency in a mature area of the field having high water cuts (85 to 90%). This project included drilling infill wells to go from an inverted seven-spot to a direct five-spot pattern, reducing the acreage from 60 to 20 acres (Ac). In 2013, the infill wells were completed without CHOPS; instead, a fracpack with proppant coated with a curable liquid resin (CLR) resistant to high pHs (i.e., the ASP fluids) was used to help prevent a possible collapse of the reservoir in the near-wellbore and entrapment of the progressive cavity pump when the ASP fluid front passed through as it would remove the residual oil that holds the sand grains together. To date, this fracpack treatment appears to have achieved the objective.
Performance Evaluation of a Newly Developed Demulsifier on Dilbit Dehydration, Demineralization and Hydrocarbon Losses to Tailings
Authors: Kailey Ishpinder , Behles Jacqueline
Published: May 2015

Chemical demulsification is a cost-effective, convenient, quick, and efficient method for breaking water-in-diluted bitumen emulsions in oil sands processing. The industry is always seeking demulsifiers that act as effective dehydrators and demineralizers, minimize rag layer formation by controlling oil/water interface, and reduce the diluent/bitumen losses to tailings. In this paper, the performance of a newly developed demulsifier “Z” was investigated for its performance on dilbit dehydration, demineralization, and hydrocarbon losses to tailings and compared against the first and second generation demulsifiers “X” and “Y”, respectively. The dehydration and demineralization efficiencies of demulsifier “Z” are 2.0 and 7.6%, respectively, higher than demulsifier “Y” and 6.4 and 10.7%, respectively, higher than demulsifier “X” at 50 ppm dosage after 15 minutes of residence time. Demulsifier “Z” also works better on the diluent and bitumen losses to the underflow as compared to demulsifier “X” and “Y”. To find the reason why demulsifier “Z” performs superior to “X” and “Y”, the solids were collected from the original froth and the top, interface, and bottom fractions of the diluted froth for characterization by X-ray diffraction analysis (XRD), X-ray energy dispersive spectrometry (EDS), scanning electron microscopy (SEM), and particle size distribution (PSD). XRD data shows that demulsifier “Z” reduced the amount of clays, iron, and zirconium oxide minerals from the top and interface dilbit fractions as compared to the control sample. PSD data shows that demulsifier “Z” reduced most of the particles of size less than 0.50 µm from the interface. Thus, demulsifier “Z” helps to resolve the interfacial material by separating the minerals that tend to form rag, especially siderite, pyrite, magnetite, rutile and anatase, from the oil/water interface and sends them to the underflow.
A Method to Calculate In–situ Water Relative-Permeability Using the Response at Observation Well Adjacent To Steam-Assisted-Gravity-Drainage Well-Pairs
Authors: Irani Mazda
Published: May 2015

Although convective heat flux is neglected in classic steam-assisted gravity-drainage (SAGD) models such as the one derived by Butler, heat convection through the condensate flow into porous media can be very important. A key control on the condensate flow is the in-situ relative-permeability to water within the reservoir. To date there is no methodology that can calculate the in-situ relative-permeability to water in SAGD reservoirs during steam injection and progression of the steam chamber. The in-situ relative-permeability to water during steam injection can be different from laboratory and well-test results. The problem with the results from lab test is that they are mostly from disturbed cores or remolded samples. And the issue with results from both lab and well testing is that at the edge of the steam chamber, bitumen undergoes thermal expansion of some 15%; therefore, unless the water saturation increases by a similar amount, water mobility is quickly decreased by the expanding bitumen phase. A method is provided to calculate in-situ relative-permeability in oil sand reservoirs using the distance between pressure and temperature response at the same depth. The implementation of the concepts is tested for Underground Test Facility (UTF) project. The results suggest that the in-situ relative-permeability to water during steam in most SAGD projects is limited to 10-4 to 10-5 and having higher relative permeabilities is only possible at lean zones. This paper describes a new method for reservoir characterization based on water mobility for different oil sand projects.
Evaluating EOR Potential in an Unconventional Heavy-Oil Reservoir with Strong Foamy Solution Gas Drive
Authors: Jamaloei B. Yadali , Singh A. R.
Published: May 2015

Murphy's Seal asset in the Peace River Oil Sands region in North West Alberta has a tremendous potential for a significant increase in production and reserves using enhanced oil recovery (EOR) methods. Seal asset, in general, is an unconventional pool due to presence of compositional gradient, faulting, water pockets, and significant variations in oil viscosity and pay-zone thickness, and varying rock dilation/fracturing in some parts. Gravity and viscosity are marked by declining quality with depth, biodegradation and compartmentalization. Murphy Oil have already been operating polymer flood and horizontal cyclic steam stimulation in the area.

Some individual wells in Seal came on stream at 150 BOPD with cumulative production to date of 125 to 225 MSTB per well. In this portion of Seal, reservoir thickness ranges 7 to 12 meters with the dead oil viscosity of 7,500 to 200,000 cp. Despite the high viscosities, strong historical production is as a result in part to good permeability, and to the foamy solution gas drive mechanism. The foamy solution gas drive has the effect of both lightening the combined oil/gas/water emulsion and providing the necessary drive mechanism to mobilize the fluids and emulsion toward the producers.

The reservoir characteristics in this portion, with strong foamy oil drive, are highly variable, and the most suitable EOR method is indeterminable without an integrated reservoir characterization and modeling. Some of the potential EOR candidates which are being evaluated for this portion include non-thermal methods (carbonated and conventional waterflood, polymer flood, polymer waterflood, water-alternating-gas (WAG) injection, solvent flood, or combinations thereof) and non-steam thermal techniques (hot waterflood, hot WAG, and hot polymer flood).

The development plan involves several steps to develop an EOR strategy for the area. Stratigraphic wells have been drilled and core samples were taken from these wells and analyzed. Carbonated waterflood and conventional cold/hot waterflood, hot/cold polymer flood, polymer waterflood, and WAG have been tested on the cores in the laboratory. The results of EOR core floods, core analysis, logging, detailed seismic and petrophysical studies as well as history-matched reservoir simulation and forecast (based on detailed lab-measured PVT) have been integrated into a full field study. Moreover, a great deal of sensitivity analysis and uncertainty assessment (using Latin hypercube design, Monte Carlo simulation, and response surface method) has also been conducted to assist in evaluating the reservoir performance using the above-mentioned EOR methods.

Addressing geological/reservoir/operational variances, this integrated field EOR study helps determine optimum EOR development in this area. It provides insight on how to screen the reservoir/operational parameters for successful EOR application in geologically-complex unconventional heavy-oil reservoirs with varying PVT behavior and strong foamy solution gas drive.
Reactive Steam Assisted Gravity Drainage Oil Sands Recovery Process
Authors: Khansari Z. , Gates I.
Published: May 2015

To extract oil from oil sands reservoirs the techniques are required that reduce the viscosity from hundreds of thousands and several millions of cP to a point that it can flow. In Steam-Assisted Gravity Drainage (SAGD) process, injected steam releases its latent heat and reduces the viscosity of the oil. This oil, referred to as bitumen, encountered steam-oil reactions process leading to aquathermolysis and steam-rock reactions - geochemical reactions. Geochemical reactions are responsible for in situ gas production and alteration of produced water composition that can affect the reservoir pressure, porosity, permeability, bitumen viscosity and thus the recovery process. In this research it has been examined that how water composition changes during SAGD operation. A reaction model was defined expressing the geochemistry of SAGD within the formation and a reactive thermal reservoir simulation was built to represent reservoirs with different shale layer geometries at various distances from SAGD wellpair. For the first time, the results demonstrated that the produced water composition can be used to detect baffles and barriers and their distances from wellpair. The analysis of produced water can be used as a tool to monitor the process dynamics and understanding the reservoir heterogeneity.
The Impact of Asphaltene Precipitation and Clay Migration on Wettability Alteration for Steam Assisted Gravity Drainage (SAGD) and Expanding Solvent-SAGD (ES-SAGD)
Authors: Kar Taniya , Yeoh Jun Jie , Ovalles Cesar , Rogel Estrella , Benson Ian , Hascakir Berna
Published: May 2015

This paper examines the wettability change during Steam Assisted Gravity Drainage (SAGD) and Expanding Solvent - SAGD (ES-SAGD). The qualitative and the quantitative analyzes of residual oil for steam and steam-solvent coinjection cases are achieved to investigate the impact of clay migration and asphaltene precipitation on wettability alteration. The solvent selection in ES-SAGD is made according to their solubility in asphaltenes; insoluble (n-hexane), soluble (toluene), and intermediate soluble (cyclohexane). Five experiments (one SAGD and four ES-SAGD) are conducted on a Canadian bitumen. Different solvent injection strategies are followed: coinjection and cyclic injection. Wettability is determined through contact angle measurements on the spent rock samples for both inside and outside steam chamber zones. Residual oil saturation is defined via solvent extraction and with a thermal method; Thermogravimetric Analysis (TGA). Two solvents are used for the extraction: toluene and mixture of 90%dichloromethane+10%methanol. The asphaltene fractions of the residual oil samples are further characterized by determining clay content, Solubility Profile; and carbon, hydrogen, sulfur, nickel, and vanadium contents. Both the thermal and the two solvent extraction methods yield more or less the same residual oil saturations. The asphaltene content of the residual oils (22 to 27 wt%) is found lower than the asphaltene content of original bitumen (34 wt%). However, higher metal content is detected on the residual oil asphaltenes. Analysis of residual oil asphaltenes shows a significant presence of clays in the inside steam chamber region for SAGD, which inhibits effective steam chamber propagation by reducing permeability. This asphaltene-clay interaction increases the oil- wetness of the rock surface and impacts the oil production adversely. However, this effect is minimized by the addition of solvents. The wettability measurements on spent rock samples also support these findings. The elemental analysis of asphaltenes reveals that with the increase in precipitation of asphaltenes (for ES-SAGD with n-hexane), there is an increase in vanadium and nickel concentrations. In terms of asphaltene Solubility Profiles, higher polarity was found for asphaltenes originated from inside the steam chamber zone for ES-SAGD with n-hexane, where the effect of n-hexane in the vapor phase is dominant. This work shows that the effectiveness of ES-SAGD may be in part caused by contributions from wettability changes, clay migration, and asphaltene precipitation in addition to by oil viscosity reduction alone. This study provides information on the interaction of clay, asphaltenes, solvent, and steam during SAGD and ES-SAGD. It explains the behavior of clay and asphaltenes during SAGD and ES-SAGD when different solvents are used.
Reservoir Simulation of H2S Production During a SAGD Process Using a New Sulfur-Based-Compositional Kinetic Model
Authors: Ayache Simon V. , Lamoureux-Var Violaine , Michel Pauline , Preux Christophe
Published: May 2015

Nowadays steam injection is commonly used as a thermal EOR method due to its efficiency for recovering hydrocarbons from heavy oils and bitumen. Reservoir models simulating this process describe the thermal effect of the steam injection, but generally neglect the chemical reactions induced by the steam injection. These reactions are called aquathermolysis and have been previously investigated through laboratory experiments. Based on these experimental results, this paper proposes a new compositional kinetic model to reproduce these reactions in the context of reservoir modeling. In particular the proposed reactions model accounts for the formation of the highly toxic and corrosive acid gas H2S in the presence of sulfur-rich heavy oil and predicts the modification of the oil SARA composition versus time that results from the aquathermolysis reactions. The overall objective of this paper is to understand the aquathermolysis reactions in reservoir undergoing steam injections and to provide the Oil companies with a numerical model for reservoir simulators that forecasts H2S production risks.

The new Sulfur-Based-Compositional Kinetic Model is firstly presented and then validated in the context of laboratory-scale experiments. Its H2S and SARA composition predictions are based on a new simplified reactive scheme of 5 reactions coupled to a compositional and thermal reservoir simulation with no mass transfer (0D). Finally the thermo-kinetic modeling is coupled with a 2D reservoir simulation of a SAGD process for a generic Athabasca oil sand. The H2S to SARA (bitumen) production ratio against time computed by the reservoir simulation is found to be consistent with data from a SAGD process in Athabasca, which validates the modeling approach followed.