bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Dolomitization on Reservoir Quality Evolution of the Fractured Carbonate Reservoir Upper Cretaceous, Onshore Abu Dhabi Oilfield, U.A.E
Authors: Farooq Umer , Caetano Hugo , Radwan EL Sayed 
Published: May 2017

Abstract
Dolomitization, as part of diagenesis of carbonate rocks, may or may not significantly enhance reservoir quality of the altered sediments. In this context, a diagenesis study was performed on Upper Cretaceous reservoir of an onshore oil field, Abu Dhabi, U.A.E. The paper elaborates facies related dolomitization and its selective influence on the reservoir quality enhancements. The framework of the study is based on detailed petrographic examination and description of 850 thin sections, isotopic compositions (C, O, Sr) of selected samples; and fluid inclusion microthermometry of dolomite formed in upper and middle reservoir units.
The study concluded that dolomitization of shoal grainstones and packstones resulted in coarse crystalline dolomite, which caused significant increase in reservoir porosity and permeability in the middle resercoir unit. Conversly, dolomitization of pretidal mudstones and wackestones resulted in microcrystalline dolomite, which has caused limted increase in the micro-porosity with little impact on permeability in the upper reservoir unit. Dolomite was formed during eo- and mesodiagenesis (Th = ca 65-90° C; salinity = 15-21 wt. % NaCl). Dolomitization of pretidal mudstones is suggested to have occurred in an evaporative setting, whereas dolomitization developed in packstones and grainstones of bioclastic shoal and subtidal sediments may have been driven by deepage reflux mechanisms. Consequently, dolomitization trend maps were produced for both middle and upper reservoir units. These dolomitization trend maps were than used as constrain to build the facies model to honor the diagenetic overprint. Blind test on integrated facies model revealed high predictiability in terms over reservoir quality distribution and production behavior in both upper and middle reservoir units. This in turn has added value to optimize field development stratergies with proper well placement into the reservoir.
Metamodeling via Hybridized Particle Swarm with Polynomial and Splines Regression for Optimization of CO2-EOR in Unconventional Oil Reservoirs
Authors: Al-Mudhafar Watheq J. , Dalton Christian A. , Al Musabeh Muzher I. 
Published: May 2017

Abstract
Various studies have been conducted to optimize oil production in unconventional reservoirs using gas injection processes. Some studies determined the optimal design of hydraulic fractures through horizontal wells while others optimized the placement of horizontal wells to maximize oil recovery. In this study, an integrated optimization workflow combining Particle Swarm and Non-parametric Proxy Metamodels was adopted to optimize oil production using CO2-EOR in shale oil reservoirs.
A pseudo-component black oil reservoir model was considered to simulate CO2 flooding in shale oil reservoirs and to predict future reservoir performance over a 30-year prediction period. The cyclic CO2 flooding optimization procedure consisted of 3 cyclic operational decision factors and 5 well constraints for 5 pairs of horizontal injector and producer wells with 8 fractures each. The cyclic injection factors included injection, soaking, and production durations over the prediction period. Minimum bottom hole pressure, maximum oil production rate, and water cut were optimized for the production wells, and maximum bottom hole injection pressure and maximum gas injection rate were optimized for the injection wells. An integrated optimization approach conducted using Particle Swarm Optimization (PSO) and Proxy Metamodeling was integrated to find the optimal level for each of the 8 factors. PSO was adopted to create a search-space swarm of candidate solutions (particles) considering the range of each operational factor. These particles were then evaluated by the reservoir simulator to calculate the cumulative oil production by the end of the prediction period. To reach the optimal solution, 100 candidate solutions were created as training experiments with 4 successive iterations of approximately 20 experiments each. The optimal solution increased oil production by 322,675 surface barrels. Next, a 2nd order polynomial regression proxy model was constructed to metamodel the large reservoir simulator. The performance of the polynomial proxy model was validated via a comparison to non-parametric algorithms of Multivariate Adaptive Regression Splines. A cross-validation was considered prior to building the proxy models by sampling and subdividing the entire dataset into two subsets: 70% training for modeling and 30% testing for prediction. The testing subset and the entire dataset were compared to the three proxy models by computing the Root Mean Square Prediction Error and the Adjusted R-square for each. It was concluded that polynomial regression is the best metamodel, followed by the MARS algorithm, to produce a simplified alternative metamodel for the reservoir simulator to evaluate the cyclic CO2 flooding in shale oil reservoirs. The most influential operational factors were also identified for their effects on the CO2-EOR process performance in shale reservoirs.
Modeling the Depletion of Fractured Vuggy Carbonate Reservoir by Coupling Geomechanics with Reservoir Flow
Authors: Zhang Fengshou , An Mengke , Yan Bicheng , Wang Yuhe 
Published: May 2017

Abstract
In this paper, geomechanics is coupled with reservoir flow for modeling the depletion and deformation in fractured vuggy carbonate reservoir. Different from the dual- and triple-porosity models or the coupled approaches in which the vugs are considered as a continuous porosity, the vugs are treated as virtual volumes in this study. For each vug, the fluid exchange at the vug-matrix interface is dynamically calculated with time evolution and the pore pressure in the vugs is updated through considering both the fluid material balance and the volume change due to the mechanical deformation of vug. The fluid-mechanical interaction in the rock matrix and natural fractures is calculated based on the framework of Biot's poroelstic theory. The mechanical and hydraulic interactions between vugs and matrix are preserved and the stress evolution due to the depletion can be dynamically updated. The results in this study show that, the depletion process is mainly controlled by the fluid storage of the vugs. Fluid modulus is thus a more sensitive parameter than the rock/fracture modulus in terms of the depletion. However, the rock/fracture modulus can also affect the deformation of the system and thus affect the volume and pressure changes of the vugs.
Investigation of the Impact of Diagenesis on Reservoir Quality in Carbonate Reservoir: A Case Study
Authors: Sabeai Jawaher Al , Lavenu Arthur P. 
Published: May 2017

Abstract
Diagenesis can enhance, preserve or degrade the reservoir quality by changing its fabric partially or completely as it will affect directly the porosity and permeability. It is anticipated that by understanding the impact of diagenesis and integrating it with the depositional settings and sequence stratigraphy will represent a powerful tool for predicting a spatial distribution of reservoir quality in carbonate reservoir located offshore Abu Dhabi, United Arab Emirates.
The study is based on sedimentological core descriptions and petrographical analysis of thin-sections for selected cored wells at field-scale. It will enable a semi- deterministic approach for the prediction of the key facies across the field. It will then be integrated with the different diagenetic processes that have been defined with respect to different relative time events.
A diagenetic sequence made of 14 different processes, which are either enhancing or degrading reservoir quality, has been defined. In parallel, 3rd and 4th order sequence stratigraphy are defined using lithofacies association and allow determining a depositional framework at field scale. Combining depositional settings with diagenetic evolution enables to define how the rock properties evolved and where are located the better quality rock in the reservoir.
The reservoir quality is controlled by the depositional environment, which controls the subsequent diagenetic processes. Hence, it is important to understand the lateral and vertical facies distribution as well as the different type of diagenetic alterations in order to have a clearer image of the spatial variation of the reservoir quality. With the help of this acquired knowledge the geologist will be aware of the reservoir limitations and could predict its behavior with time.
Seismic TI Anisotropy Estimation in Nahr Umr Shale from Walkaway VSP
Authors: Waqas Muhammad , Willemsen Pierre , Rufino Rogelio , Suliman Israa 
Published: May 2017

Abstract
Seismic anisotropy parametrization has a vital role in seismic imaging as well as in geomechanical applications. The most common form of seismic anisotropy is Transversely Isotropic (TI) caused by fine geological layering such as in shales. TI, if not incorporated can lead to geological miss-positioning of the seismic image. Walkaway VSP data was used to estimate TI parameters for the Nahr Umr shale, which is a highly anisotropic formation and is a regional cap rock.
Walkaway VSP was recorded using 16 level 3 Component (3C) downhole receiver array positioned across Nahr Umr formation with 402 surface shot points in an offshore field Abu Dhabi. Walkaway VSP provides direct information of upgoing and downgoing primary and shear waves. 3C data was oriented followed by 3C wavefield separation in order to obtain slowness and polarization of the upgoing and downgoing primary and shear waves. Slowness and polarization information gives insight to in situ wavefield propagation.
Slowness and polarization data was inverted to obtain TI anisotropy parameters along receiver array. The inversion of slowness and polarization data does not rely on overburden structural complexities hence providing robust local anisotropy estimates. Strong primary to shear wave mode conversion in the vicinity of Nahr Umr formation helped to obtain good results. The estimated TI anisotropy parameters helped to guide anisotropy parameters in Nahr Umr shale for a nearby field pre-stack depth imaging project (Waqas et al., 2016). The overburden anisotropy needs to be as accurate as possible in order to obtain better seismic imaging and characterization for underlying reservoir. The parameters can also be used in geomechanical applications.
This paper provides TI anisotropy parameters estimation for the regional highly anisotropic shale formation. The unique method was proposed for quite some time in the literature however has not been applied or reported to estimate anisotropy for the Nahr Umr shale.
Multiscale Coupling of Triple-Continuum Model and Discrete Fracture Network for Carbonate Reservoir Simulation
Authors: Zhang Na , Sun Qian , Wang Yuhe , Efendiev Yalchin 
Published: May 2017

Abstract
Multiphase flow in carbonate reservoirs has been a hard problem of scientific research for many years. Accurate flow simulation is essential for the efficient exploitation. In this paper, a coupled triple-continuum and discrete fracture network approach is developed for modeling multiphase flow through fractured vuggy porous media. Multiple levels of fractures can be not only modeled as different superimposed continua but also embodied as discrete fracture network based on their geometrical characteristics. We develop a systematic coupling using Multiscale Finite Element Method (MsFEM) as a framework for coarsening and refinement. MsFEM is used to capture subgrid scale heterogeneities and interactions through multiscale basis functions calculated based on the triple-continuum background. Unstructured mesh is applied to model discrete fractures in arbitrary. This paper presents a significant advancement in terms of elevating the limitations of the triple-continuum models in handling complex fractures and extending the model reduction capability of MsFEM. Several numerical examples are carried out to demonstrate the capability of the proposed coupling method.
A New Permeability Anisotropy Characterization Approach for Heterogeneous Reservoir
Authors: Huang J. , Wang B. , Chen H. , Liu S. 
Published: May 2017

Abstract
A new absolute permeability upscaling method based on geological hierarchical models that affect different scales reservoir heterogeneities is presented. Reservoir anisotropy is evaluated via horizontal permeability (Kh) and vertical permeability (Kv). The new approach based on the geologic viewpoint that various geologic hierarchical-elements set result in relevant permeability display of different reservoir scales. For reservoirs, from micro-scale to macro-scale, influencing factors of permeability become abstruse. In conventional scenario, the calculation method based on single-phase numerical simulation test, core analysis and data statistics integrates all these factors as much as possible to upscale permeability. Considering reservoir anisotropy, horizontal permeability (Kh) and vertical permeability (Kv) are studied to show how anisotropy changes according to different reservoir heterogeneities. In the case study of Mackay River Oil Sand Block, Alberta, Canada, database includes regional depositional setting, core, and logging data for more than 20 wells. Generally, reservoir sedimentary setting poses a direct effect on permeability. Local rock bedding affects permeability anisotropy greatly, as well. There is no obvious linear parity between horizontal permeability (Kh) and vertical permeability (Kv) in core-plug. Vertical and lateral grain size variance also alters permeability. The mm-cm scale mud drapes have a worse effect on vertical permeability (Kv) than on horizontal permeability (Kh). Besides, bioturbations in the transitional facies could be favor of permeability. The three factors have non-linear relationship on effecting permeability. The new upscaling model synthesizes all these factors to upscale the permeability for nearly all scales of reservoirs, from the scale of core to lithofacies or even to the entire reservoir. Comparisons study is also conducted between this model and current upscaling algorithms such as arithmetic average, harmonic average, etc. The results showed that the upscaling model of this paper is more reasonable. Meanwhile, reservoir characterization hierarchical models can also be applied to explicate heterogeneity effect on the attribute of reservoir fluid qualitatively. The novelty of this approach lies in solving reservoir fluids' attributes quantitatively through exact heterogeneities analysis.
Implicit Fracture Modelling for Permeability Enhancement in Carbonate Reservoirs: A Novel Approach to Bridge Data Gaps for Honoring Dynamic Observations
Authors: Lavenu Arthur P. , Howell Katharine , Kane Peter 
Published: May 2017

Abstract
In a giant carbonate reservoir, located offshore Abu Dhabi, permeability and production data are hard to reconciliate. Recent investigations on this reservoir have shown that it is affected by natural fractures. Borehole images, cores and thin-sections allowed characterizing two main fracture sets. However, the scarcity of data, with regards to the size of the reservoir, did not allow building a discrete fracture network. To overcome this gap, modelling fractures in an implicit way appears the best and simplest solution to enhance permeability and match the production data.
Implicit means that fractures are not considered as a discrete object. Instead, at the cell scale, fracture impact on permeability has been translated into multipliers in the x, y, and z directions, superimposed on the matrix permeability. The process of implicit fracture modelling is not straightforward. Building a fracture conceptual model (seismic faults, fault-related fractures, subseismic faults, and background fractures) is the starting point, to understand the big picture. The second step is defining the layer/fracture relationships, and quantifying the interaction between matrix and fractures (transmissibility). The third step is modelling and implementing the permeability modifiers in the 3D geological grid.
The distribution and occurrence of the different features remains difficult to constrain using one single deterministic model. Using multi-realization is powerful tool to get the closest match to PTA.
Deterministic scenarios have been created combining joints and faults, assigning different properties to each of the feature: size, frequency, degree of baffling, degree of permeability anisotropy, vertical transmissibility, mechanical stratigraphy, position to the structure of the reservoir…The permeability field resulting from each scenario has then be compared to PTA to determine which case best matches the dynamic data. The created permeability array is then added to the matrix permeability of the reservoir, enhancing it up to 6 times.
Implicitly modelling fractures through multi-realizations enable to get a solution that match as much as possible the PTA. In the particular case of large reservoir with scarce data, it allows geologists to have an estimate of the fracturing state of the reservoir and how these fractures are contributing to the overall field flow behavior. It is also a way of mimicking the fracture pattern in the case of few data availability, and which ultimately will enhance the quality of the history match
Uncertainties Associated with the Interpretation and Estimation of Relative Permeabilities Using In-Situ Formation Tester Measurements
Authors: Yznaga Reinaldo Jose , Quintero Luis Fernando , Negm Ehab , Arevalo Francisco , Soleiman Wael 
Published: May 2017

Abstract
Relative permeability is an essential parameter for reservoir description, engineering, and management. Relative permeabilities are typically obtained in the laboratory through evaluation of the dynamic behavior in cores using fluids that are assumed to be representative of those in the reservoir. In-situ measurements of effective permeability can provide valuable information about fluids, rock, pressure, temperature, and their interactions in the evaluated formation at original reservoir conditions. Recent technological advances allow data obtained from formation testers to be analyzed and interpreted for estimating relative permeabilities.
Formation testers are typically run when wells are drilled; therefore, using acquired data for estimating effective permeability can be cost-effective and less time-intensive compared to existing effective permeability estimation methodologies. However, the measurement process, the meaning of the acquired data, the interpretation of the data, and the resulting relative permeability values are affected by the uncertain environment associated with the entire process, which also affects the confidence of the estimated relative permeabilities and their use as an input for reservoir description, engineering, and management.
Although the use of formation testers as a tool to estimate relative permeabilities is promising, it is crucial to understand the environment in which the dynamic events occur and the impact of the uncertainties related to the physical phenomena and interactions associated with the measurement and interpretation processes. Conversion of the acquired information at the oil/gas well into inputs to properly interpret the acquired data, the models available to interpret the phenomena, and the formation tester tool capabilities all require understanding of the uncertainties associated with the entire process. These uncertainties, when properly qualified and quantified, can serve as the decision criteria to estimate the value of information (VOI) of relative permeability determination using in-situ formation tester data.
This work provides a detailed description of the uncertainties related to relative permeability estimation based on in-situ measurements of formation testers and its impact on the interpretation outputs.
Temperature Effects on Cotton Seedling Emergence, Growth, and Development
Authors: Reddy K. Raja , Brand David , Wijewardana Chathurika , Gao Wei 
Published: May 2017

Little insight of temperature effects on cotton root morphology and seed germination.
Cotton cultivars vary in their response to different temperatures.
Growth and developmental responses developed will be useful in cotton crop models.
Establishing vigorous cotton (Gossypium hirsutum L.) seedling stand for an early planted crop will help to develop healthy root and canopy development. Cotton planted early in the season will be subjected to low, but variable temperatures and soil moisture conditions. There has been little exploration of temperature effects on the cotton root system architecture. The objective of this study was to study the effects of a wide range of temperatures during seed germination and early seedling growth stages on above‐ and belowground growth and developmental parameters of four cotton cultivars. A molecular standard, Texas Marker (TM)‐1 and three modern cotton cultivars (DP1522B2XF, PHY496W3R, and ST4747GLB2) were sown at five day/night temperature regimes of 20/12, 25/17, 30/22, 35/27, and 40/32 °C (day/night). Shoot and root growth parameters were measured 20 days after planting (DAP). The small differences observed between the obsolete molecular standard, TM‐1, and the three modern cultivars in response to temperature indicate that successive breeding efforts did not change the rate or behavior of these traits to temperature. Seedling emergence was best described by both linear (TM‐1 and PHY496W3R) and quadratic (DP1522 B2XF, and ST4747 GLB2) functions. Node numbers and root tips increased linearly with increase in temperature, and no cultivar differences were observed for this trait. The functional relationships between temperature and cotton seed emergence and pre‐squaring above‐ and belowground growth and developmental responses will be useful in assisting management and in improving functionality of many cotton models for on‐farm and research and policy decisions.
Delineating Soybean Maturity Groups across the United States
Authors: Mourtzinis Spyridon , Conley Shawn P. 
Published: May 2017

Core Ideas
Seven maturity group zones were identified across the United States.
The width of maturity group zones 4 and 5 cover the largest geographic region.
Maturity group zones were defined by a downward deflection of the maturity group lines.
Maturity group adaptation zones need to be continuously monitored and adjusted.
Photoperiod and in‐season temperature are the primary factors that dictate the region where a soybean [Glycine max (L.) Merr.] variety is adapted. The first study that defined hypothetical maturity groups (MGs) zones across the US was 45 yr ago, and the most recent used data up to 2003. Although, photoperiod remains constant, climatic conditions, management practices, and soybean genetics have changed during the past decades. Therefore, the objective of this study was to re‐delineate soybean MGs across the US using recent genetics. Soybean MG‐specific yield data from variety trials conducted in 2005–2015 were aggregated from 312 locations across the United States. Seven MG zones were identified starting from MG = 0 in North Dakota to MG = 6 in southern Georgia and South Carolina. The width of MG = 4 and 5 zones cover the largest geographic region extending from north of latitude 28°N to 39°N. Additionally, in contrast to previous studies, the MG zones were defined by a downward deflection of the MG lines moving from East to West rather than convex parallel lines. Due to the strong effect of planting date on MG selection, a multi‐location‐year experiment should be conducted across the United States using multiple MGs evaluated in several planting dates. Such study could provide further insight on location‐specific optimum MG. Overall results, update current knowledge by providing valuable information for decision making and regional modeling. This work highlights the need to continuously monitor and adjust the MG zones due to the constantly changing climate, management, and genetics.