bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Insights into the Critical Role of Geology in Modeling and Prediction of Low Salinity Waterflooding
Authors: Dang Cuong T.Q. , Nghiem Long , Nguyen Ngoc T.B. , Chen Zhangxin 
Published: May 2015

Summary
Although the advantages of Low Salinity Waterflooding (LSW) have been widely reported, studies of LSW in the past two decades have mainly focused on the underlying mechanisms through core flooding experiments. For more successful and broader applications of LSW in the field scale, it is required to have a comprehensive understanding of the LSW performance with complex geological features on a large scale that has never been addressed in the past. This paper presents insights on field scale modeling and prediction of LSW to address the current challenges with: (1) an equation-of-state compositional simulator fully coupled to multiple ion exchanges, geochemical reactions, and wettability alteration; (2) incorporation of critical geological properties important in LSW; (3) effective closed-loop reservoir management for design and prediction of the LSW process; (4) LSW evaluation in a full field scale.
A mechanistic LSW model and a closed-loop modeling approach are introduced in this paper that can efficiently capture the critical effects of geology on the LSW process by integrating the use of geological software, a reservoir simulator and a robust optimizer. First, eighty geostatiscal realizations with different facies and lithology properties and distributions are generated to evaluate the effect of reservoir geology, in particular the critical effects of clay, on LSW. A wide range of recovery factors from 19% to 40% indicate that the effectiveness of LSW strongly depends on geological factors such as facies properties, clay distribution and clay proportion. In consistency with the laboratory and field-scale observations, wettability alteration has been identified as the dominant effect that contributes approximately 58% to 73% to the incremental oil recovery from these realizations. Detailed analyses of the key factors were addressed to allow the design of optimal injection strategies to maximize the oil recovery by LSW. LSW is then evaluated in a closed-loop reservoir management for a sandstone reservoir in both secondary and tertiary modes. It is found that secondary and tertiary LSW give about 6% and 4.1% incremental OOIP over high salinity waterflooding, respectively. The simulation results also indicate that the sooner the LSW process is started, the better the benefit is.
Petrofacies Determination in Unconventional Reservoirs Driven by a Simulation-to-Seismic Process
Authors: Ramsay Travis , Yarus Jeffrey 
Published: May 2015

Abstract
It is well-understood that hydraulic rock types categorize flow unit regimes in porous media such that modeling of these regimes according to hydraulic conductivity is possible in a reservoir simulator. This hydraulic characterization is necessary in reservoir simulation to spatially dictate multiphase flow behavior throughout the modeled reservoir. The spatial delineation of these multiphase data then relies on a singular relationship between petrophysical properties, which can be used to assign the multiphase properties to the simulation grid; the properties and requisite relationship of choice are between absolute permeability and porosity.
This paper illustrates that a simulation-to-seismic modeling approach can be used to reconcile large-scale flow disparities in the dynamic reservoir model, resultant of diminished spatial constraints during the creation of the static petrophysical model with seismic attribute array data. The results demonstrate that the assignment of multiphase hydraulic descriptions to petrofacies have considerable control on simulated rates and produced volumes. The examination of selected simulation scenarios leads to the conclusion that petrofacies, when derived considering petrophysical cutoffs and hydraulic rock types, provide an alternative to incorporating depositional facies constraints during the modeling of select shale reservoirs, wherein the understanding of a regionalized modeling constraint is limited. Additionally, it is shown that geologic facies are not flow units while they are considered regionalized variables. The uncertainty associated with unconstrained petrofacies is then recognized as broad; but, it is accepted that this modeled petrophysical system allows for the described petrofacies to be used as a proxy for hydraulic conductivity in the absence of a facies-based spatial constraint.
A novel approach is introduced in this work to construct petrofacies from log curves and core data to relate hydraulic rock types and petrophysical properties to the simulation grid using a methodology that honors the available seismic. The mathematical formulation used to describe petrofacies can be modest or elaborate; however, they differ from geologic facies, which can be described as regionalized variables. Unlike geologic facies, petrofacies do not adhere to interpretable geometries and thus might not be considered as regionalized variables or functionally modeled with deterministic or stochastic algorithms.
Successful Deployment of Unconventional Geomechanics to First Zipper Hydraulic Fracturing in Low-Permeability Turbidite Reservoir, Mexico
Authors: Murillo Guillermo Gutierrez , León Javier Mendez , Leem Junghun , Rojas Carolina Henriquez , Salguero Javier , Reyna Juan 
Published: May 2015

Abstract
Project “Hectarea Fracturada” by the Operating National Mexican Company was the first simultaneous stimulation of two parallel horizontal wells (i.e., zipper hydraulic fracturing) project in Latin America, implementing a reservoir-specific approach by integrating geological, geophysical, petrophysical, and geomechanical assessments. The project was executed in fields located in a basin in the north region of Mexico, which consists of alternating shales and thin bedded sandstones. The target sandstone formation at the location of two horizontal wells is deemed tighter (i.e., &gt; 1 md) than the other area in the basin.
Initial production from the two horizontal wells after a total of 32 hydraulic fracture stages was 8, 320 BOPD. The initial production was greater than 15 times the average initial production from conventional single-frac wells in the area and was approximately 40 times greater than the initial production from the vertical offset well. The production from the two horizontal wells stabilized at 2, 517 and 1, 011 BOPD, respectively. A typical conventional well in this area produced 220 BOPD, while the offset well yielded 100 BOPD. The two horizontal wells had 240, 000 bbl of 90-days cumulative production, which exceeded 14 times the average cumulative production from the conventional wells in the fields. Application of the completion technology was considered successful and was extended to other not conventional and mature fields, with similar successes.
Assessment and Ranking of EOR Strategies for Giant Extra-Heavy Oil Fields
Authors: Coll R. , Escobar E. , Carrera M. León , Pérez S. 
Published: May 2015

Abstract
This paper presents an integral methodology to evaluate and rank Enhanced Oil Recovery (EOR) strategies for heavy oil fields, together with preliminary results for a real case study in the Orinoco Oil Belt (OOB) where thermal EOR processes are planned to be used in a very large scale.
The decisions around EOR deployment are diverse, including EOR process selection, wells placement, injection conditions and scheduling. Typical decision parameters are: incremental oil recovery, Net Present Value, injection cost and environmental impact. Full field incremental recovery and injection requirements are estimated from reservoir simulation using a sectoring approach and taking into consideration the project development plan. Injection cost is highly dependent on the EOR process to be applied, as well as on specific project constraints, such as location or resources and infrastructure availability. The decision workflow uses the previously estimated full field production and injection profiles to size the surface facilities for each particular comparison case, and estimate the respective associated costs. Incremental drilling and completion costs for the EOR operations are also considered within the methodology. Environmental impact is assessed by estimating CO2 and H2S emissions, as well as energy and fresh water demands. The automation of the workflow allows the fast but meaningful assessment of hundreds of alternative strategies, including variations on EOR process conditions, surface facility configurations, deployment schedules and geological or commercial scenarios.
This workflow has been applied to a field in the OOB to support the decisions about EOR deployment strategy to be taken during the project conceptualization phase. The main objective was to identify the EOR process that could provide the best incremental recovery without infringing any project constraint, primarily target production plateau and fuel and fresh water availability, and, at the same time, minimizing cost and environmental impact. Being an extra-heavy oil field, thermal EOR processes were considered, more particularly: Cyclic Steam Stimulation (CSS), Steam Flooding (SF), Steam-Assisted Gravity Drainage (SAGD) and Horizontal Alternating Steam Drive (HASD). About one thousand cases were evaluated under uncertainty using information from different domains: geology, reservoir, wells, facilities, HSE and commercial. The comparison results provided very useful insights on the advantages, risks and drawbacks of each EOR strategy, and set the basis for a high quality decision.
PaHigh Resolution Image Log and Leached Porosity Analysis in Complex Carbonate Reservoirs
Authors: Zeghlache Mohamed Larbi , Akbar Mahmood 
Published: May 2015

Abstract
This article addresses the geological characterization of carbonate reservoir in the Middle East, using the high definition imager tool combined with other logs. In the logged wells, two main categories of open fractures were observed; 1) thin-layer-bound and 2) thick-layer bound fractures. The first category of fractures has limited vertical and lateral extents, hence may be considered as permeability enhancing at local and smaller scale. On the other hand, the second type of fractures may have larger vertical and lateral extents, hence may have larger influence on fluid movement at the reservoir scale. A conceptual fracture model was developed around one particular well path to understand their distribution and relationship with the formation layering.
In addition to fractures, the heterogeneities of these carbonates were examined through the use of newly introduced techniques. Through this analysis the total porosity measured by the petrophysical logs was dissected into leached porosity (connected and isolated ones), fractured porosity and matrix porosity.
Bilinear Flow in Horizontal Wells in a Homogeneous Reservoir: Huntington Case Study
Authors: Feng Wei Cher , Nurafza Peyman , Al-Shamma Basil , Gringarten Alain 
Published: May 2015

Abstract
In the Huntington field, bilinear flow with a clear one-quarter unit slope in the pressure derivative has been observed during intermediate-times in horizontal well tests, instead of the usual linear flow with a half unit slope expected in a homogeneous reservoir. This paper investigates various analytical methods with numerical methods to explain this behaviour.
A number of plausible explanations of this pressure behavior were investigated in this study: rate history or production-time effects; transition between early and late time derivative radial flow stabilizations which could yield a quarter slope straight line on the derivative for specific combinations of horizontal and vertical permeabilities, well length and reservoir thickness; and geological conditions such as high-permeability streaks, the presence of shale barriers, and layering with varying permeability.
It was concluded from numerical simulations and geological evidence that the most likely explanation, which yields the best match with well test data, was uniform horizontal permeability and non-uniform vertical permeability increasing from the bottom to the top of the reservoir. This is consistent with the geology of the Huntington field, where the depositional sequence is dominated by high-density turbidity currents.
At each sedimentation pulse, heavier pebble/gravel lags were deposited first at the base of channels followed by finer particles which may have formed thin shale drapes. In addition, diagenesis might have led to cementation of pebble/gravel lags. The non-uniform and non-laterally extensive occurrence of the cemented pebble/gravel lags and thin shale drapes act as local baffles to vertical flow but not to horizontal flow resulting in bilinear flow behaviour in the reservoir. This paper offers a unique insight into an integrated effort at combining analytical, numerical well test models and geological evidence to explain the reservoir behavior observed in the Huntington field.
Importance of Fines in Smart Water Enhanced Oil Recovery (SmW-EOR) for Chalk Outcrops
Authors: Chakravarty Krishna Hara , Fosbøl Philip Loldrup , Thomsen Kaj 
Published: May 2015

Abstract
In SmW-EOR it is generally believed that precipitation of brines must be avoided since it can have a negative impact on the SmW sweep efficiency. But substitution of Mg2+ by Ca2+ on calcite surfaces (a well-accepted phenomenon) can change the brine combination and enhance the possibility of fine formation at speciation. Considering this phenomenon we analyze the possibility of fines formation and its influence in SmW-EOR.
To calculate the brine speciation and the amount of precipitate formed at different pressure and temperature conditions, we use the Extended UNIQUAC model for 61 SmW-EOR experiments reported in literature. Both the amount of available soluble SO42- (aq) in the solution and the amount of CaSO4 precipitation has been calculated and correlated to the corresponding oil recovery.
Brine speciation after considering the substitution of Ca2+ by Mg2+ on chalk mineral surfaces showed possible precipitation of CaSO4 in most of the brine solutions. The amount of CaSO4(s) precipitate formed, increased with temperature and consequently the dissolved soluble SO42-(aq) decreased. Increased concentration of Ca2+,Mg2+ or SO42- ions compared to Sea Water-(SW) also enhanced the amount of precipitate formed. Increasing NaCl concentrations increased the solubility of SO42- and Ca2+ in SmW and decreased the amount of precipitate formed. The amount of precipitate formed in the pore space (after the substitution of Mg2+ on calcite surface) consistently correlated to the increased oil recovery observed in various experiments. While in several cases additional oil recovery did not correlate to the amount of soluble SO42- present in the SmW at equilibrium. These results together suggest that the substitution reaction on the mineral surface followed by solid fines formation is the fundamental reason behind the observed EOR. These results indicated that the observed wettability alteration in chalks may not be the primary cause but an additional effect of SmW-EOR.
This study shows how Extended UNIQUAC model can be used as a rigorous mathematical tool for understanding of the SmW-EOR in chalk. It also quantitatively explains a series of previous experiments reported in the literature and shows the importance of fine formation in SmW-EOR, both through correlation between modeling and experiments.
Experimental Study of Low Salinity and Optimal Salinity Surfactant Injection
Authors: Khanamiri Hamid Hosseinzade , Torsæter Ole , Stensen Jan Åge 
Published: May 2015

Abstract
Both experimental and field trials have shown that low salinity water (LS) injection produces incremental oil recovery. One of the major advantages of LS is that it lowers salinity, resulting in favorable conditions for the addition of chemicals such as surfactants to enhance oil recovery. Surfactant flooding can benefit from lower ionic strength as it becomes possible to use a large variety of surfactants which are not applicable at higher salinities. Lower surfactant adsorption at lower ionic strength reduces the need for using alkali. Surfactant injection can also be implemented at a lower concentration and probably without the need for a co-surfactant when used with LS water. These advantages may result in a cost-effective and more environmentally friendly chemical EOR.
In this investigation, laboratory surfactant flooding experiments were conducted with aged Berea sandstone cores. The samples were aged using a typical crude oil from the Norwegian Continental Shelf. In-situ brine contained both monovalent and divalent cations. The surfactant sodium dodecylbenzenesulfonate (SDBS) was used at concentrations of 0.05wt% and 0.2wt% to enhance oil recovery. In tertiary surfactant injection, low salinity surfactant (LSS) is injected after LS water and a high salinity water (HS) injected as the chase water after surfactant; however in after-tertiary surfactant injection the sequence was HS-LS-LSS. Combination of LS water with high salinity surfactant (HSS) was also investigated in two experiments with injection sequences of LS-HSS-HS and HS-HSS-LS. HS is waterflooding with the same salinity as in the HSS. HSS solution had ultralow interfacial tension with the crude oil.
LSS flooding with 0.2wt% SDBS concentration did not result in higher oil recovery than the flooding with 0.05wt% SDBS in tertiary LSS injection. Tertiary LSS injection had a better recovery than the after-tertiary LSS. Recovery by only surfactants in HS-HSS-LS was higher than that in LS-HSS-HS. However the whole injection in the latter had higher recovery than the former. All the results were reproduced through repeating experiments on a different type of Berea sandstone. Results were discussed in terms of ionic exchange between the rock and aqueous phase, surfactant retention and phase behavior. Interfacial tensions at different salinities were measured to find the optimal salinity before injection. Rock samples were characterized in micro scale using X-ray micro-CT, and the geometrical properties of pore and throat size distribution were extracted.
Maintaining optimal conditions of a multicomponent system during a dynamic flooding in alkaline-surfactant-polymer (ASP) is challenging. Produced oil and water by multiple chemicals is also expensive to treat. Improving performance of surfactant flooding by manipulating salinity and ionic composition of brine seems to be more convenient than designing and controlling a complex ASP injection.
The Effect of Mineral Deposition on CO2 Well Injectivity
Authors: Sokama-Neuyam Y. A. , Ursin J. 
Published: May 2015

Abstract
This paper presents results from laboratory investigations of CO2 injectivity losses in sandstone cores driven by minerals deposition. Parameters studied includes effect of brine salinity, gas injection rate and rock permeability. The results of the study indicates that mineral precipitation and CO2 injectivity is indeed dependent on brine salinity. We report that, injecting low salinity water into the core after mineral deposition could recover CO2 injectivity. Below certain salinity of brine, we observed significant injectivity is lost probably due to clay swelling effects. The results also indicates that mineral deposition depends on the brine displacement rate. We observed low injectivity losses at high gas injection rates. The investigation also revealed that mineral deposition effects depends on intial sandstone core permeability. Injectivity losses are significant in cores with lower initial permeability.
Wellbore Implosion: Case Study of Perforation Enhancement
Authors: Saadi Hassan Al , Mirza Muhammad , Jumaat Mohd Shafie 
Published: May 2015

Abstract
Good perforating practices are equally important for water injectors as for producers to achieve effective and efficient reservoir pressure support, which, in turn, results in better field productivity. An aspect of good perforating practice is to achieve clean perforations so that the injection skin is minimized. Dirty perforations, whether due to perforation debris or crushed zones around the perforation tunnel can affect a well's injectivity. This problem is further compounded when well injection starts as particles in injection water quickly accumulate at the perforations, causing rapid injectivity drop. Therefore, clean perforations are important to deliver good well injectivity.
This is a case study of a wellbore implosion technique on perforations of injector wells in a field in Oman. Compared to perforating in a high-pressure reservoir, achieving clean perforations in a low-pressure reservoir is more difficult as perforating has less potential to breakdown the crushed zone and to purge the crushed material together with the debris from the perforation tunnels. This problem may be overcome by the wellbore implosion technique, using a dynamic underbalance system.
Various perforating systems were tried for injector wells in this field. Reactive liner shaped charge, propellant system, and post-perforating dynamic underbalance techniques were used in the same well. A dynamic underbalance gun that creates wellbore implosion was designed, and recorded pressure gauge data were matched to the simulated data. Reservoir properties of each well from the logs and from the well injectivities after applying the above-mentioned perforating systems were compared. As the principle in this case study is perforation cleanup, it is also relevant to producers. It is also relevant to other wells whether on land or offshore, both producers and injectors of any pressure regime that could be suffering from poor cleanup of perforations.
Corrigendum
Authors: Loveman Emma , Copley Vicky R , Colquitt Jill , Scott David A , Clegg Andy , Jones Jeremy , O’Reilly Katherine MA , Singh Sally , Bausewein Claudia , Wells Athol 
Published: May 2015

SummaryA previous version of this report was published in July 2013. The report was corrected on page v in November 2013. For further information, or for copies of the original material, please contact Nihredit@soton.ac.uk.
Hepatoprotective effects of <i>Sapium sebiferum</i> in paracetamol-induced liver injury
Authors: Hussain Liaqat , Akash Muhammad Sajid Hamid , Tahir Madeha , Rehman Kanwal 
Published: May 2015

<span><em>Sapium sebiferum</em> leaves were used to determine its hepatoprotective effects against paracetamol-induced hepatotoxicity in mice. A dose dependent study was conducted using two different doses (200 mg/kg and 400 mg/kg) of the extract of </span><em>S. sebiferum</em><span> against toxic effects of paracetamol (500 mg/kg) in experimental animal model. Silymarin (50 mg/kg) was used as standard drug to compare therapeutic effects of </span><em>S. sebiferum</em><span> with control and paracetamol-treated groups. Paracetamol significantly increased the serum levels of liver enzyme markers like alanine aminotransferase, aspartate aminotransferase, alkaline phosphatase, total bilirubin, and direct bilirubin. The extract showed protective effects by normalizing the liver enzymes markers in a dose dependent manner. Histopathological results confirmed the hepatoprotective effects of leaves of </span><em>S. sebiferum</em><span>. We conclude that leaves of </span><em>S. sebiferum</em><span> have strong hepatoprotective effects against paracetamol-induced liver injury and can be used in liver injuries caused by drug-induced toxicity.</span>