bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical Compartmental Model for Shale-gas Production by Multiple-Fractured Horizontal Wells Considering Transport Influenced by Nano-pore Proximity
Authors: Milad Benmadi , Civan Faruk , Devegowda Deepak , Sigal Richard F. 
Published: June 2014

Abstract
A practical simulation model is developed and demonstrated with applications for accurate characterization of production rate and pressure behavior with time in shale-gas reservoirs featuring horizontal wells intersected with multi-stages of hydraulic fractures. The model determines the contribution of each fracture stage to the overall production and predicts the pressure changes occurring in the fracture and matrix zones by a compartmental simulation approach. Various flow regimes of drawdown test are investigated for fracture diagnosis with different fracture permeability values to determine the external boundary effect. Our practical mathematical modeling, coupling the wellbore and reservoir hydraulics, is solved numerically by an iterative method to determine the flow rates coming into the horizontal well from multiple hydraulic fractures like the commingled layers intersected by a vertical well. This approach provides a reasonable description of behavior of multiple stages in shale gas reservoirs by considering the alteration of the gas transport properties and the changing apparent permeability under the effect of pore proximity of shale. Various applications of our non-Darcy simulation model demonstrate the importance of the corrections relevant for shale-gas reservoirs compared with the conventional Darcy flow without consideration of such corrections. Commensurate with field observations, when the non-Darcy flow corrections are considered, the cumulative gas production is higher compared with the conventional Darcy flow calculations which impact significantly on fracture and matrix pressure responses and production forecasting.
Fluid Compositional Prediction in Conventional and Unconventional Petroleum Systems
Authors: Horsfield B. , di Primio R. 
Published: June 2014

Abstract
In conventional petroleum systems, predicting gas-oil ratio and charge volumes ahead of drilling is a proven element of exploration strategy. In shale plays the liquid-gas cut-off must be known precisely, and production from the liquid-prone zone optimised. In-place does not necessarily correspond to produced GOR. In particular the transition from volatile oil, to condensate to wet gas is crucial, and production strategies must be developed accordingly. The first step in unravelling the fractionation phenomena occurring in both play types is to determine the bulk composition of the petroleum that is first-formed in the source rock. This is because all subsequent processes simply act upon and modify this original composition. Here we present numerous case studies where PhaseKinetics (di Primio and Horsfield, 2006), a compositional kinetic approach for predicting in-situ bulk fluid properties, has been employed in appraising acreage, and then go on to consider some of the critical aspects surrounding unconventional plays. In high pressure-high temperature (HPHT) reservoirs of the North Sea, which can be considered closed systems, black to light oil GOR distributions in the North Sea Viking Graben closely matched the predictions from our MSSV pyrolysis experiments (method of Horsfield et al., 1989) performed on the Draupne Formation source rock (di Primio and Skeie, 2004). In a similar study of the Jade and Judy Fields in the Central Graben (di Primio and Neumann, 2008), GOR predictions from MSSV pyrolysis bore a close resemblance to the natural HPHT system. Other examples of excellent GOR predictive capability are provided by modelling the Egret Shale and its generated petroleum in the Jeanne d'Arc Basin, Canada (Baur et al., 2012), and the Bakken Shale and its petroleums in the Williston Basin, USA (Kuhn et al., 2010, 2012). The lessons learned from conventional systems about petroleum compositional predictions can be readily applied to shale resource plays. Of key importance is the structure of the precursor organic matter, determined by organofacies and maturity. This applies both vertically and laterally. We also draw attention to the importance of determining whether cumulative or instantaneous fluids are found within the range of pore sizes present in shale. In the mid- to late oil window, instantaneous fluids from the Posidonia Shale are rich in gas and light liquids; phase envelopes change rapidly with increasing maturity. Cumulative fluids in juxtaposed strata have lower GORs. Fracking has to take these points into account or production GOR might turn out to be quite different to in-situ GOR, a phenomenon that has already been noted for the Eagle Ford.
Oil Shale In-Situ Upgrading by Steam Flowing in Vertical Hydraulic Fractures
Authors: Lee K. , Moridis G. J. , Ehlig-Economides C. A. 
Published: June 2014

Abstract
Oil shale, an organic-rich impermeable rock, is an abundant energy resource in the United States. Because few oil shale deposits occur in shallow formations, application of an in-situ process is necessary for thermal decomposition and subsequent oil and gas production. An earlier investigation indicated that cylindrical or planar in-situ electric heaters were more efficient than flowing steam through created fractures. This study investigates the efficiency of oil shale in-situ upgrading by steam flowing in vertical fractures. There are challenges in the through description of in-situ upgrading process because the kerogen decomposition involves of a series of complex and sensitive reactions, and results a large number of fluid and solid products. Expanding the Flow and Transport Simulator (FTSim) developed by Texas A&M University, we developed a fully implicit capability that describes the decomposition of kerogen in the oil shale and the resulting system changes with minimal simplification and assumptions. The decomposition process is represented by 6 kinetic reactions (resulting 10 components and 4 phases), involves coupled processes of mass transport and heat flow, and accurately accounts for phase equilibrium and phase transition thermodynamics. We applied our simulator to find a successful strategy for hydrocarbon production using steam that flows in vertical fractures created by multistage transverse fracturing in a horizontal (MTFH) well. The simulation of simultaneous heating and flowing provides the system change of oil shale reservoir during in-situ upgrading, and it indicates the necessary condition of successful hydrocarbon production from oil shale reservoir.
Difference in Behavior of the Waterflood Mechanism in Two Typical Areas of a Fractured Carbonate Reservoir, McElroy Field
Authors: Nguyen Hanh D. , Somerville James M. 
Published: June 2014

Abstract
The McElroy field is one of the oldest waterflood fields in the world producing from fractured carbonate reservoirs. The field has been producing since the 1920's and started waterflooding in the 1950's. It is obvious that the waterflood process plays an important role in improving oil recovery. However, due to the complex fractured carbonate reservoir setting, it is a big challenge for the waterflood management to attain the ultimate oil recovery. Geologically, the field is divided into four main areas. Each area behaves differently as a result of the waterflood process being influenced by the varying characteristics of the fractured reservoir. Understanding the waterflood mechanism's behavior in each area will help to develop an appropriate strategic waterflood plan. This study focuses on characterizing the differences between the waterflood performances in two areas of the field, the Low Permeability Area (LKA) and the Low Pressure Area (LPA).
The study used a database of about 680 wells within the LKA and LPA to define the contrasting waterflood performances in these areas. The main characteristics of the waterflood in the LKA and LPA to be discussed in this study consist of: –Oil production performance–Water production performance–Oil recovery performance–Waterflood management - the challenges and optimization opportunities
The main objective of the study is to define the similarities and distinctions of the waterflood mechanism performance of these two different fractured reservoir areas. This study also recommends further approaches to improve recovery efficiency in the McElroy field. The analysis can be used as a reference for waterflood design process in green or brown fields exhibiting similar conditions.
Mixtures of Anionic-Cationic Surfactants: A New Approach for Enhanced Oil Recovery in Low-Salinity, High-Temperature Sandstone Reservoir
Authors: Li Yingcheng , Zhang Weidong , Kong Bailing , Puerto Maura , Bao Xinning , Sha Ou , Shen Zhiqin , Yang Yiqing , Liu Yanhua , Gu Songyuan , Miller Clarence , Hirasaki George J. 
Published: June 2014

Abstract
Test results from mixtures of anionic-cationic surfactants significantly broaden the application scope for conventional chemical Enhanced Oil Recovery methods; these mixtures produced ultra low Critical Micelle Concentrations (CMC) as well as ultra-low interfacial tension (IFT) and high oil solubilization that promote high oil recovery.
Mixtures of anionic and cationic surfactants with molar excess of anionic surfactant for EOR applications are described herein. Physical chemistry properties, such as surface tension, CMC, surface excess and area per molecule of individual surfactants and their mixtures were measured by Wilhelmy Plate Method. Morphologies of surfactant solutions, both surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP), were studied by Cryo TEM. Phase behaviors were recorded by visual inspection including with crossed polarizers at different surfactant concentrations and different temperatures. Interfacial tensions between normal octane, crude oil and surfactant solution were measured by spinning drop tensiometer method. Properties of interfacial tension, viscosity and thermal stability of surfactant, surfactant-polymer, and alkaline-surfactant-polymer solutions, were also tested. Static adsorption on sandstone was measured at reservoir temperature. IFT was measured before and after multiple contact adsorptions to recognize the influence of adsorption on interfacial properties. Forced displacements were conducted by flooding with water, polymer, SP and ASP. The core flooding experiments were conducted with water made of a simulated formation brine having approximately 5000 ppm TDS, and with a crude oil from a Sinopec reservoir.
A Novel Water Ionic Composition Optimization Technology for SmartWater Flooding Application in Carbonate Reservoirs
Authors: Yousef A. A. , Ayirala S. C. 
Published: June 2014

Abstract
Injection water with selective ionic content and composition is an essential requirement for SmartWater flooding application in carbonate reservoirs. SmartWater depleted in monovalent ions, but enriched in sulfates and divalent cations is desired for optimum incremental oil recovery in carbonates, which constitutes very complex water chemistry when compared to sandstones. Recognizing the utmost importance of water chemistry in the SmartWater flooding application, a novel water ionic composition optimization technology was investigated in this study. The proposed technology makes use of membrane desalination processes in a unique configuration to provide multiple water streams of widely varying ionic strength and content. Different water streams obtained from the novel solution can be effectively blended to yield SmartWater cocktail of desired ionic strength, composition and monovalent to divalent ion content optimally suited for carbonates.
SmartWater cocktails obtained from the proposed solution are also suited for application in other EOR processes such as polymer flood, surfactant flooding, dilute surfactant flooding, carbonated water flooding, miscible gas flooding and as boiler feed water in steam floods. Investigated scheme thereby offers a novel "one shop" solution to meet the complete suite of desired water chemistry requirements for different IOR/EOR processes. In addition, results of comparative evaluation between the investigated technology and other already known advanced desalination schemes highlight key advantages of the new solution in terms of better water ion tuning flexibility, higher recovery efficiency, lower energy requirement/foot-print and ease in operation.
Long Term Stability of Acrylamide Based Polymers during Chemically Assisted CO2 WAG EOR
Authors: Tovar Francisco D. , Barrufet Maria A. , Schechter David S. 
Published: June 2014

Abstract
CO2 flooding often results in poor sweep efficiency due to the high mobility ratio caused by its low viscosity. To mitigate this problem alternate injection of water and CO2 slugs, known as the water-alternating-gas process (WAG) is widely applied. Recently, numerical simulation and core flood experiments indicate that the use of chemicals in the water slug may improve mobility control during WAG, thus increasing the ultimate recovery and reducing the requirements for newly purchased or recycled CO2. Therefore, stability studies of common polymers used for EOR applications in CO2 saturated environments becomes necessary to address the technical and economic feasibility of this process.
In this paper, we report the results of two commonly used EOR polymers, a co-polymer of acrylamide and acrylate and a co-polymer of acrylamide and ATBS (2-acrylamido-terbutylsulfonic acid). To establish a base line for comparison, parallel experiments were conducted in two different oxygen free environments: one with CO2 and the other with nitrogen. Samples were hydrated and aged at reservoir temperature over 328 days. To isolate the effect of CO2 on the polymer, the water used for their hydration was stripped out of dissolved oxygen and the divalent cation concentration was decreased to reduce thermal and chemical degradation. Polymer samples were distributed in several bottles and removed at different times, and their apparent viscosity was measured as a function of shear rate and fitted to a power law model. The ability of the polymer solutions to retain their original apparent viscosity over time was used to quantify polymer degradation.
The results of this work show that CO2 impacts polymer stability, causing further degradation in both polymers tested when compared with the solutions aged with N2. The co-polymer of acrylamide and ATBS exhibited higher resistance to CO2 degradation as it was able increase its viscosity to 104 % of its initial apparent viscosity after 328 days, compared with the co-polymer of acrylamide and acrylate which only retained 54 % of its initial apparent viscosity after 215 days. Chemical degradation, hydrolysis and pH that affected the behavior of apparent viscosity over time also are addressed. We conclude that commercial polymers can be used during chemically assisted CO2 WAG when low divalent cation water is used at a reservoir temperature of 122 F.
Wettability, Trapping and Fracture-Matrix Interaction during WAG Injection in Fractured Carbonate Reservoirs
Authors: Agada Simeon , Geiger Sebastian 
Published: June 2014

Abstract
Relative permeabilities show significant dependence on the saturation path during enhanced oil recovery. This dependence (or hysteresis) is particularly important for water-alternating-gas (WAG) injection, a successful EOR method for clastic and carbonate reservoirs. WAG is characterized by an alternating sequence of drainage and imbibition cycles. Hysteresis is hence common and results in trapping of the non-wetting phase, which impacts incremental recovery. The competition of trapping and geological heterogeneity during WAG, particularly in carbonate reservoirs, is not yet fully understood.
In this study, we therefore use a high-resolution simulation model of a Jurassic Carbonate ramp, which is an analogue for the highly prolific reservoirs of the Arab D formation in Qatar, to investigate the impact of non-wetting phase trapping during miscible and immiscible WAG in heterogeneous carbonate formations. We then compare the impact of trapping on recovery to the impact of heterogeneity in wettability and reservoir structure. We test end-member wettability scenarios and multiple rock types. We also compute effective fracture permeabilities using discrete fracture networks (DFN), ranging from sparsely distributed background fractures to fracture networks where intensity varies with proximity to faults.
The results enable us to analyse and compare WAG efficiency in carbonate reservoirs by ranking the impact of physical displacement processes (imbibition, drainage, trapping, miscibility) versus heterogeneity (wettability, faults, fractures, layering) that are typical for carbonate reservoirs. We show that while miscible WAG injection gives better displacement results than immiscible WAG injection or water flooding for this reservoir, recovery efficiency is limited by structurally induced bypassing and flow channelling. This bypassing is magnified if fractures are considered, leading to an earlier breakthrough of injected fluids and ultimate recoveries that are at least 8% lower compared to matrix-only models. We also demonstrate the impact of different hysteresis models and show that when irreversibility of the drainage and imbibition scanning curves during WAG is accounted for, trapping is enhanced and at least a 5% increase in recovery is observed. This modelling approach, therefore, enables us to increase the reliability of WAG simulations by accounting for trapping and its interaction with wettability, miscibility, and geological heterogeneity in fractured carbonate reservoirs.
Representing Slow Foam Dynamics in Laboratory Corefloods for Enhanced Oil Recovery
Authors: Kapetas L. , van El W. A. , Rossen W. R. 
Published: June 2014

Abstract
On the laboratory scale, foam can be slow to come to steady state (local equilibrium). In fitting dynamic foam corefloods, if local equilibrium does not apply, it is essential to understand and fit the dynamics so that an accurate local-equilibrium model can be applied on the field scale. We report an attempt to represent slow foam dynamics using a simple first-order kinetic expression for the approach of foam to steady state in a population-balance model. In particular, we attempt to fit a case of gas injection into a surfactant-saturated core ("SAG" injection) (Ma et al., 2013), where the peak in pressure difference across the core takes place well after gas breakthrough, in violation of most local-equilibrium foam models. As the kinetics of foam generation are slowed in our model, the peak pressure gradient is reduced, but the timing of the peak remains at the time of gas breakthrough, i.e. after less than one pore volume injection. For sufficiently slow kinetics, the peak can be broadened significantly by spreading of the traveling wave at the shock at the foam front.
We survey published population-balance models for mechanisms that could give a late peak in pressure gradient in a SAG coreflood. Most previous studies with population-balance models use parameter values that would give rapid foam generation and a peak in pressure drop at gas breakthrough in a SAG coreflood. The data of Ma et al. suggest an abrupt onset of foam generation later in the coreflood. To represent it, we believe some sort of triggering mechanism for foam generation (for instance, pressure gradient) is needed in the population-balance model. Another possible mechanism leading to a late peak is a nonlinear response of gas relative permeability to gas trapping and refining foam texture.
A Hierarchical Model Calibration Approach with Multiscale Spectral-Domain Parameterization: Application to a Structurally Complex Fractured Reservoir
Authors: Kang SukSang , Bhark Eric , Datta-Gupta Akhil , Kim JangHak , Jang IlSik 
Published: June 2014

Abstract
A hierarchal history matching algorithm is proposed that sequentially calibrates reservoir parameters from the global-to-local scale in consideration of parameter uncertainty and the resolution of the data. Parameter updates are constrained to the prior geologic heterogeneity and are performed parsimoniously, or only to spatial scales that can be resolved by the historical data. In the first step of the workflow, a genetic algorithm (GA) is used to calibrate and assess the uncertainty in global parameters (e.g., regional fracture properties, aquifer strength) that influence reservoir energy and field-scale flow behavior. To identify the reservoir volume over which each parameter region is applied, a novel heterogeneity segmentation technique is developed from spectral clustering theory. After an ensemble of calibrated model realizations is identified using the GA, the ensemble is reduced via a cluster analysis to define a variance-preserving subset of the members for the second step of local, higher-resolution parameter calibration. Each member of the subset is calibrated to well-level phase rate and pressure data using a sensitivity-based scheme. To improve the ill-posedness of each high-resolution inverse problem, the heterogeneity field is parameterized in the spectral domain using the Grid Connectivity-based Transform (GCT) to provide a compressed representation that captures only the sensitive geologic trends. The GCT concurrently imposes geological continuity during calibration and promotes minimal changes to each prior ensemble member.
The proposed calibration workflow is applied to a structurally complex, fractured reservoir located offshore Peru. The reservoir is modeled as dual porosity and single permeability (DPSP). In the global calibration step, the field water production rates, gas rates and average reservoir pressure are matched using the GA together with zonal multipliers that represent spatial variation in aquifer strength, fracture porosity and a matrix-fracture coupling parameter. In the subsequent local step, the well-by-well production histories are matched through calibration of the most uncertain grid-cell parameter, fracture permeability, which is characterized using the GCT parameterization. The final calibrated models are consistent with geologic interpretation and are currently being applied for field development strategies.
Solvent Enhanced Steam Drive
Authors: Hedden Ralf , Verlaan Marco , Lastovka Vaclav 
Published: June 2014

Abstract
In recent years the addition of a hydrocarbon solvent (usually in the range of C4 to C20) to Cyclic Steam Stimulation (CSS) or Steam Assisted Gravity Drainage (SAGD) operations in heavy oil (bitumen) reservoirs has become an attractive process. We extend the idea of solvent addition to steam to a Vertical well Steam Drive (VSD), and investigate the recovery mechanisms, impact on the ultimate recovery and oil steam ratio. The process is studied in core flooding experiments and a CT scanner was used to monitor the saturation distribution over time. These results are history matched using Shell's in-house numerical reservoir simulator MoReS. The simulations show that the dominant recovery mechanism is facilitated through the formation of a solvent bank. Accurate modeling and understanding of the recovery mechanism enables optimal design of the solvent co-injection process in a vertical well steam drive. This allows a comparison between a VSD and a CSS development using solvent addition to steam and selection of the best development option for a given reservoir.