bluuebunny/crossref_metadata_2025_split huggingface dataset:
Intelligent Production Modeling Using Full Field Pattern Recognition
Authors: Khazaeni Y.. , Mohaghegh S.D.. D. 
Published: December 2011

Summary
Production-data analysis has been applied extensively to predicting future production performance and field recovery. These applications operate mostly on a single-well basis. This paper presents a new approach to production-data analysis using artificial-intelligence (AI) techniques in which production history is used to build a fieldwide performance-prediction model. In this work, AI and data-driven modeling are used to predict future production of both synthetic- (for validation purposes) and real-field cases.
In the approach presented in this article, production history is paired with field geological information to build data sets containing the spatio-temporal dependencies among different wells. These dependencies are addressed by compiling information from closest offset wells (COWs) that includes their geological and reservoir characteristics (spatial data) as well as their production history (temporal data).
Once the data set is assembled, a series of neural networks are trained using a back-propagation algorithm. These networks are then fused together to form the intelligent time-successive production-modeling (ITSPM) system. This technique uses only the widely available measured data such as well logs and production history of existing wells to predict future performance of the existing wells and production performance of the new (infill) wells. To demonstrate the applicability of this method, a synthetic oil reservoir is modeled using a commercial simulator. Production and well-log data are extracted into an all-inclusive data set. Several neural networks are trained and validated to predict different stages of the production. The ITSPM method is used to estimate the production profile for nine new wells in the reservoir. Furthermore, ITSPM is also applied to two giant oil fields in the Middle East. The first one has more than 200 wells and 40 years of production history. ITSPM's production predictions of the four newest wells in this reservoir are compared with their actual production. The second real field has hundreds of wells producing from multiple layers. The field has undergone waterflooding for almost its whole life. This case also shows the capabilities of this technique in more-complex scenarios and especially multiphase systems.
Modeling Facility-Expansion Options Under Uncertainty
Authors: Jablonowski C.. , Ramachandran H.. , Lasdon L.. 
Published: December 2011

Summary
During the concept comparison and selection phase of capital projects, decision makers compare development options and select one option to carry forward to detailed engineering. This effort is often complicated by uncertainty in one or more of the critical inputs. Therefore, project teams typically investigate how different assumptions about the uncertainty influence optimal decisions. In cases where initial investment decisions are costly to change, the analysis of facility flexibility increases in importance. The goal is to find the optimal balance between initial capacity and the allocation of space and other resources for future expansion. This paper reports the results of a research project in which the authors develop an integrated asset model for a hypothetical deepwater asset and use the model to investigate various aspects of facility design under uncertainty. The method produces estimates for the optimal initial capacity, the likelihood of expansion, the expected size of expansion, and the willingness to pay for the option to expand. The approach is systematic; the model solves quickly and, thus, enables a wide scope of uncertainty analysis. The graphical output is intuitive and facilitates communication between the facility engineer, subsurface engineers, and management.
Near-Well-Subdomain Simulations for Accurate Inflow-Performance-Relationship Calculation To Improve Stability of Reservoir/Network Coupling
Authors: Guyaguler B.. , Zapata V.J.. J. , Cao H.. , Stamati H.F.. F. , Holmes J.A.. A. 
Published: December 2011

Summary
Externally coupled workflows that rely on exchanging inflow-performance relationships (IPRs) at the coupling points, such as those between reservoir and surface-network simulators, may exhibit oscillations because of the IPR calculated at the beginning of a timestep not being representative of the IPR at the end of the timestep. One solution is to have an implicitly coupled reservoir/surface system. This is often impractical because the reservoir and the surface network may be modeled using different applications, or the resulting coupled system may become too large and too complex to solve implicitly because of processing time and convergence issues. We propose the calculation of multipoint IPRs obtained by solving near-well subdomains for the subsequent timestep. A flexible reservoir-simulation architecture enables the dynamic creation and simulation of near-well subdomains at run time. Subdomains are created automatically within the vicinity of the well or may be defined dynamically from the pressure gradient. These near-well-subdomain simulations are embedded within the full-field simulation and extract all the required model properties (pressure/volume/temperature, rock) from the full-field model. The most recent fluxes from the global solution are used as boundary conditions for the near-well subdomains. In this paper, the subdomain IPRs are used within reservoir/network coupling workflows for which traditionally calculated IPRs result in oscillations and high errors. Sensitivity analysis is carried out on the extent of the subdomains and the size of the coupling timestep. A real field case is used to show that subdomain IPRs result in smooth pressure/ rate profiles as opposed to the oscillatory profiles obtained from explicitly calculated IPRs and that they also help reduce balancing errors between reservoir and surface models.
Rheology of a New Sulfonic Associative Polymer in Porous Media
Authors: Seright R.S.. S. , Fan Tianguang , Wavrik Kathryn , Wan Hao , Gaillard Nicolas , Favéro Cédrick 
Published: December 2011

Summary
For hydrophobically associative polymers, incorporating a small fraction of hydrophobic monomer into a hydrolyzed polyacrylamide (HPAM) polymer can promote intermolecular associations and thereby enhance viscosities and resistance factors. In this paper, we investigate the behavior of a new associative polymer in porous media. The tetra-polymer has low hydrophobic-monomer content and a molecular weight (Mw) of 12–17 million g/mol. Total anionic content is 15–25 mol%, including a few percent of a sulfonic monomer. This polymer is compared with a conventional HPAM with 18–20 million g/mol Mw and 35–40% anionic content. Rheological properties (viscosity vs. concentration; and shear rate and elastic and loss moduli vs. frequency) were similar for the two polymers [in a 2.52% total dissolved solids (TDS) brine at 25 °C]. For both polymers in cores with permeabilities from 300 to 13,000 md, no face plugging or internal-filter-cake formation was observed, and resistance factors correlated well using the capillary-bundle parameter. For the HPAM polymer in these cores, low-flux resistance factors were consistent with low-shear-rate viscosities. In contrast, over the same permeability range, the associative polymer provided low-flux resistance factors that were two to three times the values expected from viscosities. Moderate shear degradation did not eliminate this effect—nor did flow through a few feet of porous rock. Propagation experiments in long cores (up to 157 cm) suggest that the unexpectedly high resistance factors could propagate deep into a reservoir—thereby providing enhanced displacement compared with conventional HPAM polymers. Compared with HPAM, the new polymer shows a significantly higher level of shear thinning at low fluxes and a lower degree of shear thickening at high fluxes.
The Fractured Triangle; A Graphically Aided Technique to Characterize Naturally Fractured Reservoirs from Pressure Transient Analyses
Authors: Elkewidy Tarek 
Published: December 2011

Abstract
This new technique is introduced to characterize all kinds of naturally fractured (secondary porosity) reservoirs, including carbonates, basements, and clastics on the Megascopic scale of well testing delineation. The technique is based on an original view of pressure transient data (buildup). In fact, this technique bridges between the Macro, Meso, and Megascopic scales of reservoir characterizations.
Conventional well testing analysis techniques, e.g. Horner method, do not often work for naturally fractured reservoirs since they are based on a homogeneous reservoir model. In addition, all available techniques to characterize naturally fractured reservoirs from pressure transient analyses are very much theoretical models based on unrealistic geometrical assumptions. They lack practical applications and produce limited information.
The new technique has the merit of working on real reservoir data. It utilizes pressure buildup data through the fact that formation fluids travel across different systems in heterogeneous naturally fractured reservoirs; matrix, fractures and the damaged area. A unique graphical characterization of shut-in well pressure versus time will illustrate the effect of fluid movements from the matrix system (or the tiny fractured system) through the main fracture system and across the damage area, if any, into the well. Fluid movements through each system are represented graphically. The technique is further optimized through application of pressure derivative methods to yield a very characteristic graphical representation (triangle) of each hydraulic "flow" unit in the reservoir.
The presence of the triangle sides can be used to confirm the existence of a secondary porosity system (fractures) and/or damaged area. The slopes and intersection values of the straight lines are utilized into exclusive formulas to yield the most important petrophysical and engineering parameters about the heterogeneous naturally fractured reservoir (and, in many cases, other kinds of reservoirs) including: effective fractures, matrix and skin systems volumes, partitioning coefficient, fracture intensity index, formation resistivity factor, formation tortuosity, effective drainage radius, damage radius, effective cementation exponent, fracture porosity, matrix porosity, storativity ratio, in addition to fracture permeability, matrix permeability, damaged (skin) permeability, average permeability, pressure drop across the damage area, skin factor, damage permeability, average/dimensionless diffusivity factor, flow efficiency, damage ratio/factor, economic implication of formation damage, average hydraulic "flow" unit quality index. This document and presentation will cover the theory behind the technique and present actual field application examples.
The Characterisation of Heavy Oils and Tar-Bitumen Deposits - Southern Iraq Oilfields
Authors: Ali Abdullah A. 
Published: December 2011

Abstract
The study area contains oil reservoirs in Cretaceous and Upper most Jurassic Formations, at different depths and in a variety of lithologies. There is having in the same area, several possible source rocks for such hydrocarbon.
The term "solid bitumen", as used in this study, implies in a general sense an immovable and highly viscous, or solid, oil-derived precipitate under reservoir conditions. Several natural processes leading to the deposition of solid bitumen in a reservoir have been proposed in the literature since they were first reported in the Western Canada basin in the early 1970, Three principal processes which are the most frequently cited in the literature are thermal alteration, deasphalting, and biodegradation. Thermal alteration (maturation) of pre-existing liquid hydrocarbons to form hydrogen-depleted carbonaceous residues and associated gases can result in deposition of solid bitumen in the carrier bed and reservoir at an elevated temperature.
The Effects of Asphaltene Precipitation and Deposition Control Parameters on Reservoir Performance: A Numerical Approach
Authors: Khanifar Ahmad , Demiral Birol , Darman Nasir 
Published: December 2011

Abstract
Asphaltene precipitation and deposition problems are one of the severe problems which some reservoirs may face with them during their production life. Asphaltene deposition can affect on reservoir performance such as porosity and permeability reduction, wettability alteration, moreover it may lead to plugging of wellbore and production surface facilities. These effects can be modeled by consideration some asphaltene control parameters by activation asphaltene option in compositional simulation package. These parameters are usually estimated from core flooding experiments.
This paper mentions the concept of asphaltene modeling and its related parameters and also describes the numerical study results of the effect of asphaltene precipitation and deposition control parameters on reservoir performance, by using a compositional simulation model with asphaltene modeling options. For this purpose, the real reservoir geology model and fluid data are used. After tuning the equation of state (EOS) by analyzing the oil properties data and setting the asphaltene control parameters, the simulation model is built by incorporation of the EOS for asphaltic oil properties and the asphaltene parameters into the compositional simulation model. The model enables the simulation of asphaltene precipitation, flocculation, and deposition including adsorption, plugging, and entrainment. Also, it can show the resulting reduction in porosity and permeability and changes in oil viscosity and rock wettability according some range of asphaltene control parameters.
The model is used to investigate the effects of these parameters selection on reservoir performance, including oil production, recovery factor and average reservoir pressure, also, asphaltene behavior including precipitation, flocculation, adsorption, plugging and entrainment, moreover, formation damage and its effect of rock wettablity changes. The results show the effect of the asphaltene precipitation and deposition parameters selection on reservoir performance clearly, so it should correctly calibrate and carefully use them for modeling. Also, for reservoir that does not have any asphaltene core flooding experiment, they will be useful for estimating the asphaltene model input parameters and its effect on simulation results.
Flexural Wave Dispersion Analysis for Reservoir Characterization with a Small Diameter Cross Dipole Tool
Authors: Eccles David , Mayor Terry , Zheng Yibing , Elkington Peter 
Published: December 2011

Abstract
Differences between observed and forward modelled flexural wave dispersion characteristics in cross dipole sonic logging in homogeneous formations are useful for evaluating mud invasion and for differentiating between stress-induced and fabric-related anisotropy. In this paper we investigate the sensitivity of the dispersion effect to borehole size and mud slowness, and show the importance of taking account of the tool’s mechanical properties in the forward model - particularly when the tool diameter is a substantial fraction of the well diameter. We demonstrate that a new generation of small diameter cross dipole tool has a small tool-effect in common hole sizes, and extend the dispersion model results down to hole diameters less than 4 inches; we verify the calculations with real data sets acquired in sub 4-inch wells, as well as larger wells up to a 12 inches diameter. The results are also used to examine the size of dispersion corrections needed to calculate shear slowness in situations where low frequencies from the broadband transmitter are coupled relatively weakly to the formation.
Laboratory Rock Characterization Study for Optimized Sand-Control Completion Using Samples Selected from Pre-Khuff Reservoir
Authors: Alqam Mohammad H. , Al-Badairy Hamid H. , Caliboso Edwin T. , Al-Shammary Hussain A. 
Published: December 2011

Abstract
The production of sand into the wellbore is one of the oldest problems in the oil and gas industry. The produced sand could lead to plugging-off the wellbore, erosion of surface equipments, and the settlement on the surface facilities. There are two options currently available to control the sand production: (1) restricting the production rate and ultimately controlling the drawdown pressure that will cause the load-bearing formation from failing at higher stress. (2) Using mechanical/ chemical ion control techniques to prevent the formation sand from entering the wellbore.
This study focuses on investigating the role of rock mechanics, particle size distribution and characterization study for sand control completion. The Knowledge gained from the investigation will be used to build up in-house know-how and skills which enable the setting of new guidelines for evaluating and designing of the best type of sand control techniques.
An integrated approach was applied to investigate the role of rock mechanical properties, sand texture, particle size distribution and location of clays materials within the pore structure in sandstone samples selected from Pre-Khuff reservoirs. Ultrasonic compressional and shear velocities were measured on each sample and dynamic Young's modulus and Poisson's ratio were obtained. Eight representative samples were selected from the wells under study for mineralogical characterization and for identification of the clay types and their distribution within the samples by using X-ray Diffraction (XRD) and Environmental Scanning Electron Microscopy (ESEM) analytical techniques. Dry sieve analysis and ESEM were also conducted on samples selected from various depths. In addition, porosity and permeability measurements were conducted on the samples.
The results, showed that porosity level ranges from 29%- 4.0% and permeability ranges from 968 - 0.1md. The XRD analyses conducted on the samples indicated the presence of Dolomite, Microcline and their disappearance, which has more cementing characteristic compared to other minerals. The grain-coating cement was evident; this provides a significant cementation to the grains and tends to have more strength and high friction angles.
The samples tested from some of the wells follow the reported relationship between unconfined compressive strength and porosity. There is inverse relationship between these two important properties. This relationship will provide us with a correlation chart to find out the Unconfined Compressive Strength (UCS) of other interval in the formation.
Full Field Reservoir Geological Model Integrating High Resolution Sequence Stratigraphy: Nahr Umr Sandstone, Block 5, Offshore Qatar
Authors: Klem Niels Korsholm , van Buchem Frans , Hoch Esbern 
Published: December 2011

Abstract
Oil bearing ultra thin, shallow marine sandstones, with a thickness of only 3 – 5 ft are present in the Upper Aptian - Middle Albian lower part of the Nahr Umr Formation in Block 5, offshore Qatar. The sands have been produced for 16 years from horizontal wells and Nahr Umr has now reached a mature development stage where identification of further infill opportunities requires very detailed reservoir characterization studies and extensive simulation work. This paper describes how integration of core studies and detailed palynological analysis has improved the understanding of both the reservoir architecture and the reservoir quality distribution. This approach allowed construction of a deterministic 3D static model, which was used for dynamic simulation work.
The high resolution sequence stratigraphic model is based on the detailed description of 28 cored vertical wells, a core gamma-ray controlled log calibration, and a closely spaced palynological sampling. The lower part of the Nahr Umr Formation consists of a large variation of sedimentary facies, including sandstones, claystones, oolitic ironstones and carbonate mudstones and wackestones. In addition, locally, carbonate and siderite cement are present as well as varying amounts of authigenic glauconite. These facies are organized in six different types of small scale (decimeter to metre scale) cycles, which form a stacking pattern controlled by the 3rd order depositional sequences. The obtained insight in the systematic and predictive spatial distribution of sedimentary facies forms the framework for the reservoir model, with the best reservoir units occurring in the sandstone dominated cycles, whilst low permeable silts, iron-rich clays, iron ooids and carbonates form flow baffles between the main pay zones. Facies maps for each cycle were refined with input from horizontal well data, thus further improving the input for the full field static reservoir model. Calibration of the modelled flow properties against dynamic flow data obtained from numerous Mini-DST's provided a valuable quality check of the model properties.
Electrokinetics of Limestone and Dolomite Rock Particles
Authors: Alotaibi Mohammed B. , Nasr-El-Din Hisham A. , Fletcher James J. 
Published: December 2011

Summary
High-salinity water such as seawater, or formation brines, is frequently injected in carbonate reservoirs. Ion interactions between injection water, reservoir fluids, and rock surface are quite complex. It has recently come to be believed that the chemistry of injection water can significantly enhance oil recovery. Several reaction mechanisms were suggested, including rock dissolution, change of surface charge, and/or sulfate precipitation.
This study attempts to characterize the electrokinetics of limestone and dolomite suspensions at 25 and 50°C. In addition, reaction mechanisms at the water/rock interface were established. Synthetic formation brine, seawater, and aquifer water were chosen from Middle East reservoirs. Carbonate particles were soaked in high- and low-salinity water. A phase-analysis-light-scattering (PALS) technique was used to determine the zeta potential (surface charge) of carbonate particles over a wide range of pH, ionic strength, and temperature.
Zeta potential of limestone particles was significantly affected by calcium ion. Low-salinity water created more negative charges on limestone and dolomite particles by expanding the thickness of the diffuse double layer. Individual divalent cations decreased the zeta potential of limestone particles in sodium chloride solutions, while sulfate ions showed a negligible effect. Limestone particles in high-salinity water had decreased zeta potential. The solubility of calcium ions increased as temperature was increased and thus created additional negative charges. The absence of sulfate in aquifer water strongly influenced the dolomite surface charge. In summary, surface-charge adjustment from positive to negative can alter the wettability of carbonate rock from preferentially oil-wet to water-wet. As a result, residual-oil saturation should be decreased.