bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Oil Recovery Pilot Testing Best Practices
Authors: Teletzke G.F.. F. , Wattenbarger R.C.. C. , Wilkinson J.R.. R. 
Published: March 2010

Summary
Enhanced-oil-recovery (EOR) implementation is complex, and successful applications need to be tailored to each specific reservoir. Therefore, a systematic staged evaluation and development process is required to screen, evaluate, pilot test, and apply EOR processes for particular applications. Pilot testing can play a key role in this process. Before field testing, pilot objectives need to be clearly defined and well spacing, pattern configuration, and injectant volumes determined.
This paper outlines a staged approach to EOR evaluation and focuses specifically on pilot testing best practices. These best practices were derived from ExxonMobil's extensive piloting experience, which includes more than 50 field pilot tests covering the full range of EOR processes. Topics covered include: (1) determining whether a pilot is needed and defining pilot objectives, (2) considerations for successful pilot design, (3) types of pilots and their advantages and disadvantages, (4) tools and techniques for assessment of key reservoir mechanisms, and (5) minimizing uncertainty in pilot interpretation. Key issues that are often addressed by pilots are discussed, including areal sweep and conformance, gravity override, viscous fingering, and loss of mobility control. Also included are aspects of instrumentation and measurements in pilot injection, production, and monitoring wells. Several ExxonMobil piloting examples are used to illustrate the best practices, including a single-well injectivity test, an unconfined pilot with observation wells, a small-scale confined pilot, and a large-scale multipattern pilot.
Correlating Optimum Stage Pressure for Sequential Separator Systems
Authors: Al-Jawad Mohammed S. , Hassan Omar F. 
Published: March 2010

Summary
A study to find the optimum separators pressures of separation stations has been performed. Stage separation of oil and gas is accomplished with a series of separators operating at sequentially reduced pressures. Liquid is discharged from a higher-pressure separator into the lower-pressure separator. The set of working separator pressures that yields maximum recovery of liquid hydrocarbon from the well fluid is the optimum set of pressures, which is the target of this work.
A computer model is used to find the optimum separator pressures. The model employs the Peng-Robinson equation of state (Peng and Robinson 1976) for volatile oil. The application of this model shows significant improvement of all objective functions for many oils (Hassan 2004).
Mathematical correlations for estimating optimum set of pressures have been deduced from the model to provide simple and quick tools to find the optimum stages pressures. Many tests have been achieved with many volatile samples at different conditions to prove the validity of these correlations.
Ensemble-Based Closed-Loop Optimization Applied to Brugge Field
Authors: Chen Yan , Oliver Dean S. 
Published: March 2010

Summary
In this paper, ensemble-based closed-loop optimization is applied to a large-scale SPE benchmark study. The Brugge field, a synthetic reservoir, is designed as a common platform to test different closed-loop reservoir management methods. The problem was designed to mimic real field management scenarios and, as a result, is by far the largest and most complex test case on closed-loop optimization. The Brugge field model consists of nine layers with a total of 44,550 active cells. It has one internal fault and seven rock regions with different relative permeability and capillary pressure functions. There are 20 producers and 10 injectors in the field. Noise corrupted production data are provided monthly. Each well has three different completions that can be controlled independently. The producing life of the reservoir is 30 years, and the objective of optimization is to maximize the net present value (NPV) at the end of 30 years.
Because of the complexity of this test case, several advanced techniques are used in order to improve the solution of the ensemble-based closed-loop optimization. First, covariance localization was used to obtain good model updates with a relatively small ensemble of reservoir models. Localization alleviated the effect of spurious correlations and made it possible to incorporate large amounts of data. Second, covariance inflation was used to compensate for the tendency of small ensembles to lose variability too quickly. When covariance inflation was used together with localization, variability in the ensemble was maintained. Third, regularization was also used in the ensemble-based optimization to reduce the effect of spurious correlations and to smooth the optimized control parameters. Fourth, normalized saturations were used in the state vector because different rock regions had different relative permeability endpoint saturations. Finally, the addition of global parameters such as relative permeability curves and initial oil/water contact (IOWC) reduced the tendency for overshoot. The resulting combination of ensemble-based data assimilation and optimization performed very well on the benchmark study, achieving an NPV within 1% of the value obtained by the test organizers with known geology.
Numerical Simulation of the In-Situ Upgrading of Oil Shale
Authors: Fan Y.. , Durlofsky L.J.. J. , Tchelepi H.A.. A. 
Published: March 2010

Summary
Oil shale is a highly abundant energy resource, though commercial production has yet to be realized. Thermal in-situ upgrading processes for producing hydrocarbons from oil shale have gained attention recently, however, in part because of promising results reported by Shell using its in-situ conversion process (Crawford et al. 2008). This and similar processes entail heating the oil shale to approximately 700°F (371°C), where the kerogen in the shale decomposes through a series of chemical reactions into liquid and gas products. In this paper, we present a detailed numerical formulation of the in-situ upgrading process. Our model, which can be characterized as a thermal/compositional, chemical reaction, and flow formulation, is implemented into Stanford's General Purpose Research Simulator (GPRS). The formulation includes strongly temperature-dependent kinetic reactions, fully compositional flow and transport, and a model for the introduction of heat into the formation through downhole heaters. We present detailed simulation results for representative systems. The model and heating patterns are based on information in Shell publications; chemical-reaction and thermodynamic data are from previously reported pyrolysis experiments. After a relatively modest degree of parameter adjustment (with parameters restricted to physically realistic ranges), our results for oil and gas production are in reasonable agreement with available field data. We also investigate various sensitivities and show how production is affected by heater temperature and location. The ability to model these effects will be essential for the eventual design and optimization of in-situ upgrading operations.
Development, Testing, and Field Application of a Heavy-Oil Pipeline-Cleaning Chemical: A Cradle-to-Grave Case History
Authors: Wylde Jonathan J. , Slayer Jubal J.L. 
Published: March 2010

Summary
This paper details the complete evolution of a new cleaning chemical for heavy-oil and gas pipelines. Information is offered regarding the reason for development, the research involved in formulation of the new product, and the laboratory testing. This paper concludes by giving several case histories of application in cleaning operations in the western United States and Texas.
Oil naturally contains paraffins, asphaltenes, and naphthenates. During transport, these hydrocarbon components can precipitate and adhere to the pipeline walls and can become associated with iron sulfide scale. Corrosion can often occur on pipeline walls under these organic deposits. Pigging operations are normally performed to remove organic and inorganic debris from the walls of a pipeline. However, these scales can become very compacted and adhere to the walls of the pipeline. It is often necessary to add surfactant-based chemicals to assist in the breakup, softening, and transportation of these deposits.
A literature review of the current theory in the chemistry of pipeline-cleaning chemicals is presented together with a critical account of the key properties required of these chemistries: wettability alteration, solubilization efficacy of organic materials, emulsification of phases, dispersion, detergency, and defoaming.
An explanation of the laboratory development and evaluation has been given as a preamble for the case histories. One case history details how a pipeline operator unsuccessfully tried to clean a 12-in., 9-mile section of pipeline with a pig. The pig was launched and became stuck along the length of the pipeline. Application of the newly developed product was able to free the stuck pig and removed significant debris. By way of conclusion, the paper offers suggestions on how chemicals can be most efficiently used in conjunction with these programs.
Unstructured-Coarse-Grid Generation Using Background-Grid Approach
Authors: Evazi M.. , Mahani H.. 
Published: March 2010

Summary
Reservoir flow simulation involves subdivision of the physical domain into a number of gridblocks. This is best accomplished with optimized gridpoint density and a minimized number of gridblocks, especially for coarse-grid generation from a fine-grid geological model.
In any coarse-grid generation, proper distribution of gridpoints, which form the basis of numerical gridblocks, is a challenging task. We show that this can be achieved effectively by a novel grid-generation approach based on a background grid that stores gridpoint spacing parameters.
Spacing parameter (L) can be described by Poisson's equation (∇2L = G), where the local density of gridpoints is controlled by a variable source term (G); see Eq. 1. This source term can be based on different gridpoint density indicators, such as permeability variations, fluid velocity, or their combination (e.g., vorticity) where they can be extracted from the reference fine grid. Once a background grid is generated, advancing-front triangulation (AFT) and then Delaunay tessellation are invoked to form the final (coarse) gridblocks. The algorithm produces grids varying smoothly from high- to low-density gridpoints, thus minimizing use of grid-smoothing and -optimization techniques. This algorithm is quite flexible, allowing choice of the gridding indicator, hence providing the possibility of comparing the grids generated with different indicators and selecting the best.
In this paper, the capabilities of approach in generation of unstructured coarse grids from fine geological models are illustrated using 2D highly heterogeneous test cases. Flexibility of algorithm to gridding indicator is demonstrated using vorticity, permeability variation, and velocity. Quality of the coarse grids is evaluated by comparing their two-phase-flow simulation results to those of fine grid and uniform coarse grid. Results demonstrate the robustness and attractiveness of the approach, as well as relative quality/performance of grids generated by using different indicators.
New Correlations for Critical and Subcritical Two-Phase Flow Through Surface Chokes in High-Rate Oil Wells
Authors: Al-Attar Hazim H. 
Published: March 2010

Summary
The critical and subcritical multiphase flow through wellhead restrictions of a prolific oil field in the Middle East is investigated, and two sets of new correlations are presented. The first set of correlations is developed by using 40 field tests representing critical flow conditions. The second set of correlations is based on 139 field tests representing subcritical flow conditions of gas/liquid mixtures through wellhead chokes.
For the critical multiphase flow condition, the predicted oil flow rates by the new set of correlations are in excellent agreement with the measured ones. The absolute average percent difference (AAPD) is between 1.88 and 4.37, and the corresponding standard of deviation (SD) is between 2.52 and 6.52. These results are found to be statistically superior to those predicted by other published correlations considered in this work. During the subcritical gas/ liquid flow conditions through surface chokes, the accuracy of oil flow rates predicted by the new set of correlations seems to be sensitive to the type and size of the choke being used. For Cameron LD type and 144/64-in. choke, the oil flow rates predicted by the proposed correlation are superior to those predicted by other methods available in the literature, with AAPD of 8.5. However, for smaller choke sizes of 96/64 and 64/64 in., the oil flow rates predicted by the new correlations and other methods are found to be close to each other. For Cameron F type and 144/64-in. choke size, the oil flow rates predicted by the new correlation are closely matched by those predicted by other published methods, with AAPD of 13.7. For smaller choke sizes of 80/64 and 64/64 in., few field tests are available, and the predications of all methods, including the proposed ones, show similar statistical results. The above findings for Cameron F choke also seem to apply to beaned wellhead assemblies for this particular oil field.
Quantifying Nonuniform Aquifer Strength at Individual Wells
Authors: Izgec O.. , Kabir C.S.. S. 
Published: March 2010

Summary
In waterdrive reservoirs, the aquifer influx experienced by each well is a function of reservoir heterogeneity and operating variables. Solving multiwell field problems necessitates estimating this variable influx. Yet no simple approach allows us to discriminate this differential influx commensurate with well characteristics. Direct application of analytical aquifer models, being applicable to the entire reservoir, is nondiscriminating, particularly when inferring individual well influx is concerned. In contrast, numerical models allow flexibility with the use of pore-volume multipliers in the aquifer cells; however, actual experience shows that approach to be less than satisfactory.
This paper outlines a method for modeling differential aquifer influx received at each well; the combined use of capacitanceresistance model (CRM) and analytic aquifer model underpin the proposed approach. This study presents an unsteady-state aquifer formulation, without the need for dimensionless aquifer-function tables. The formulation allows treatment of both unsteady-state and pseudosteady-state flow behaviors with the simplified form of the van Everdingen and Hurst (vEH) formulation. This aquifer model is then coupled with CRM on an individual-well basis. In other words, because each well is attached to a different aquifer model, appropriate water influx can occur commensurate with rock properties, fluid withdrawal rate, aquifer size, etc. A synthetic example verifies and a field example validates the proposed method.
Saturated-Steam Pressure Drop in Flow Through Porous Media
Authors: Closmann Philip J. 
Published: March 2010

Summary
This note provides a simple steady-state method for estimating the pressure drop for steam vapor flowing at a constant mass rate through porous media. The derived formula includes the relevant properties of saturated steam and allows for their distribution along the zone of pressure variation. It also eliminates the need for steam tables within the applicable pressure range (10-2,900 psia). The method can also be extended to cases in which the rate varies in a known manner because of heat loss or other factors.
Rheological Properties of a New Class of Viscoelastic Surfactant
Authors: Li L.. , Nasr-El-Din H.A.. A. , Cawiezel K.E.. E. 
Published: March 2010

Summary
Surfactant-based acid systems were developed over the last few years for diversion to overcome the severe problems caused by polymer residue and crosslinker precipitate after polymer-based system treatments during matrix and fracture acidizing. Two main types of viscoelastic surfactants have been used: amphoteric and cationic. Surfactant molecules can form rod-like micelles and significantly increase the viscosity in the presence of salts. After acid treatments, the surfactant gel can be broken by mixing with hydrocarbons, external breakers, internal breakers, or by reducing the concentration of salts and or surfactant through dilution with water.
This paper introduces a new type of viscoelastic-amphoteric surfactant (amine oxide). It carries a positive charge in live HCl acids. The effects of acid additives and Fe(III) contamination were examined on its rheological properties. Measurements were made at temperatures from 75 to 220°F and 300 psi at various shear rates from 0.01 to 935 sec-1. Acid additives included corrosion inhibitors, a mutual solvent, a nonemulsifying surfactant, iron-control agents, and a hydrogen-sulfide scavenger.
The apparent viscosity of surfactant solutions prepared in deionized water, live acid, and spent acid was found to be a function of temperature. Apparent viscosity of live surfactant-based acids was also found to be a function of HCl concentration. Fe(III) contamination caused enhancement of apparent viscosity, then two immiscible liquids, and finally precipitation of surfactant/Fe complex. A demulsifer and mutual solvent decreased the apparent viscosity at all temperatures examined. Multiple iron-control agents were tested and found to reduce the apparent viscosity of this surfactant-based acid. Only up to 1 wt% methanol can be used with this spent-acid system at temperatures below 175°F.
Slug Control With Large Valve Openings To Maximize Oil Production
Authors: Ogazi A.I.. I. , Cao Y , Yeung H.. , Lao L.. 
Published: March 2010

Summary
Severe slugging in an offshore riser pipeline imposes a major challenge to production and flow assurance in the oil and gas industry. Riser-top-valve choking has shown effectiveness in eliminating severe slugging. However, most manual-choking and active-control techniques were tuned by trial and error, resulting in an operation at a smaller-than-necessary valve position for a stable-flow condition. This imposes unnecessarily high backpressure on the riser pipeline, which leads to reduction in production. One way to overcome this problem is to design the active-control system to operate at a large valve position. However, at such an operating point, the riser-pipeline system is naturally open-loop unstable associated with severe slugging flows.
In this work, an approach to tune a robust proportional-integralderivative (PID) slug controller at an open-loop unstable condition is proposed. First, at an open-loop unstable operating condition, a reliable linear model is derived from the nonlinear simplified riser/separator model (SRSM) developed in previous work. Then, a robust stabilizing PID controller is designed on the basis of the linearized model.
The controller was successfully applied to a 2-in. laboratory riser at Cranfield University and an 8-in. generic industrial riser system modeled in the commercial multiphase-flow simulator OLGA. Simulation on the industrial riser system shows that the proposed approaches not only can eliminate severe slugging but also can increase oil production. It also shows that the percentage improvement in oil production compared with manual choking will increase as the well pressure declines. This means that adopting active slug control is even more beneficial for mature oil fields than for relatively new fields.
The result is very significant for mature fields that are susceptible to severe slugging and low oil production because of declining reservoir pressure.
Hierarchical Ensemble Kalman Filter
Authors: Myrseth Inge 
Published: March 2010

Summary
This paper presents the hierarchical ensemble Kalman filter (HEnKF) as a robust extension of the ensemble Kalman filter (EnKF). The HEnKF is developed to be robust against features like estimation uncertainty and rank deficiency related to covariance estimation in EnKF. The HEnKF imposes a hierarchical model on the state variables and uses prior distributions from the Gauss conjugate family of distributions to obtain more-robust estimates. An empirical study demonstrates that the HEnKF provides more-reliable results than the traditional EnKF approach. Better predictions and more-realistic prediction intervals are provided. The latter is caused by model-parameter uncertainty being an integral part of the HEnKF approach, while this effect is ignored in traditional EnKF. The two versions of the ensemble Kalman filter are also compared on a synthetic-reservoir study. The HEnKF appears as significantly better.
Measurements and Modelling of Phase Behaviour and Viscosity of a Heavy Oil/Butane System
Authors: Yazdani A. , Maini B.B. 
Published: March 2010

Abstract
Solvent-based heavy oil recovery methods are of interest as environmentally friendly alternatives for thermal techniques. The phase behaviour data from a heavy oil/solvent system are important information required for feasibility studies and numerical simulation of such processes. The scarcity of experimental data in the literature is a challenge in modelling of solvent involving processes. The variety of the solvent/oil mixtures, which are being evaluated within ongoing researches such as the VAPEX (vapour extraction of heavy oil) process, requires accurate description of the system's pressure, volume and temperature (PVT) properties.
In this study, an experimental setup was designed to perform a series of PVT experiments and viscosity measurements. The results of the PVT tests conducted with the Frog Lake heavy oil and butane as a solvent are presented. The same oil/solvent pair was used in the VAPEX experiments previously reported by the authors(1, 2). The measurements include the solvent solubility in the oil, mixture density and mixture viscosity at different saturation pressures.
To simulate the phase behaviour of the system, an equation of state (EOS) was tuned using the measured experimental data and a phase behaviour package (WINPROP). The predicted densities and saturation pressures by the EOS are in very good agreement with the experimental data. A mixing viscosity correlation was also tuned with the measured data and found to be representative for describing the viscosity of the system. The viscosity data were compared with the predictions of several other available correlations, and it was shown that Shu's model(3) reproduces acceptable data for reservoir simulation purposes.
Introduction
Solvent-involving recovery processes have recently gained some attention. These processes often involve relatively light hydrocarbon solvents such as C3 - C7, which are sometimes co-injected with non-condensable gases such as CO2, CH4 and N2. Numerical simulation studies of such processes are, however, in early stages to investigate the feasibility of field implementation, improvement and optimization. Numerical modelling of these processes is mostly performed on compositional simulators to capture the potential compositional changes, asphaltene precipitation and diffusion/dispersion mechanisms. Phase behaviour of the heavy oil/solvent system is one of the most vital pieces of input data that can be predicted and produced by either a series of k values or a tuned EOS. Nonetheless, both methods rely on accurate experimental phase behaviour information.