bluuebunny/crossref_metadata_2025 huggingface dataset:
Alkaline/Surfactant/Polymer Processes: Wide Range of Conditions for Good Recovery
Authors: Liu Shunhua , Li Robert Feng , Miller Clarence A. , Hirasaki George J.
Published: March 2010

Design of an alkaline/surfactant/polymer (ASP) process requires knowledge of the amount of soap formed under alkaline conditions from naphthenic acids in the crude oil. We show here for several crude oils that, when substantial acid is present, the acid number determined by nonaqueous-phase titration is approximately twice that found by hyamine titration of a highly alkaline aqueous phase used to extract soaps from the crude oil. This acid number by soap extraction should provide a better estimate than nonaqueous-phase titration because the extracted soap interacts with the injected surfactant to form surfactant films and microemulsion droplets during an ASP process.

In a previous paper (Liu et al. 2008), an unusually wide range of salinities of ultralow oil/water interfacial tensions (IFTs) was found for one alcohol-free crude-oil/anionic-surfactant system under alkaline conditions where naphthenic soaps were present. Solubilization results indicate that this favorable behavior exists with the same surfactant blend and another crude oil.

In the same paper, a 1D simulator for the ASP process was presented. Here, this ASP simulator has been used for various acid contents, injected-surfactant concentrations, slug sizes, and salinities to show that high recoveries of waterflood residual oil (> 90%) can be expected for a wide range of near-optimal (Winsor III) and underoptimum (Winsor I) conditions for a constant-salinity process, even with relatively small slug sizes. A key factor leading to this good performance is development of a gradient in soap/surfactant ratio, which ensures that a displacement front with ultralow IFT forms and propagates through the formation. Similar high recoveries can be attained for certain Winsor II conditions but only for much larger slug sizes, owing to the tendency for surfactant to partition into the oil phase and become retarded. Large dispersion, such as might be expected for field conditions, can reduce recovery significantly for small surfactant slugs even for near-optimal and underoptimum conditions. However, this problem can be overcome by injecting the slug or drive at salinities below reservoir salinity, thereby creating a salinity gradient.
Effect of HCl Acid and Brines on Water-Swelling Packers
Authors: Al-Yami A.S.. S. , Nasr-El-Din H.A.. A. , Al-Humaidi A.S.. S. , Al-Arfaj M.K.. K. , Al-Saleh S.H.. H.
Published: March 2010

Achieving successful zonal isolation during well completion is critical to minimize early water production. Currently, cementing is the only method used in Saudi fields to provide zonal isolation. However, in horizontal sections, cementing becomes a challenge and excessive water production can occur because of channeling. Another method for zonal isolation is to use a rubber elastomer bonded onto a base pipe. The rubber swells in water and provides a seal between the base pipe and the open hole.

This paper will outline the step-by-step qualification testing that was carried out in Saudi Aramco facilities in an attempt to improve zonal isolation in horizontal and multilaterals wells.

In this study, we present laboratory evaluation of elastomers at 190°F using brines of different ionic strengths and pH values. The evaluation involved examining the effect of salinity and pH on elastomer swelling rate. Also, the study investigated the effect of 15 wt% hydrochloric acid (HCl) on swollen elastomers and whether the exposure to water after acid would restore their sizes. To the best of the authors' knowledge, no previous work has been performed to examine the impact of these factors on the swollen packers.

The elastomer bonded onto pipes was tested in autoclaves. The pressure drop across the pipes was measured as a function of time. The influences of pH and divalent cations on water-swelling packers were investigated using elastomer samples. Swelling was related to fluid characteristics.

Some water-swelling packers withstood pressures up to 5,000 psi at 190°F after placing the elastomers in brines with salinities up to 200,000 mg/L. However, the swollen elastomers shrank in 15 wt% HCl. A calcium chloride (CaCl2) completion fluid, a common fluid used in Saudi Aramco fields, at 72 lb/ft3 (pcf) failed to swell the elastomers. Re-exposure of shrunken coupons to water did not restore their initial swollen volume before acid soaking. This paper discusses the advantages and limitations of water-swelling elastomers and gives recommendations for successful field applications.
Simplified Modeling of Turbidite Channel Reservoirs
Authors: Alpak Faruk O. , Barton Mark D. , van der Vlugt Frans F. , Pirmez Carlos , Prather Bradford E. , Tennant Steven H.
Published: March 2010

Effective properties can represent fine-scale geologic heterogeneities in simple full-field reservoir models without having to model them explicitly. A comprehensive simulation study tests the sensitivity of dynamic connectivity in turbidite channel reservoirs to a large number of stratigraphic and engineering parameters. Simulations performed using geologically realistic sector models at multiple levels of stratigraphic resolution show that dynamic connectivity is governed by large-scale architectural parameters, such as meander-belt size, net-to-gross ratio, degree of depositional-storey amalgamation, and stratigraphic parameters that describe the shale architecture at multiple scales (e.g., shale-drape coverage and shale-drape frequency of occurrence).

We demonstrate how to rapidly generate effective properties at multiple geologic scales, incorporating the effect of channel architecture and reservoir connectivity into simple dynamic models. Use of simple dynamic models in conjunction with effective properties, principally geologically based pseudorelative permeabilities, accelerates the simulation workflow significantly. We show that a statistical distribution of the recovery factor (RF) can be produced within hours instead of days by the combined use of Monte Carlo simulation and a simple dynamic model with effective properties. Recovery factors estimated with our simplified modeling method agree well with observed RF distributions of turbidite channel reservoirs with significant production history.
Measurement of Nonwetting-Phase Trapping in Sandpacks
Authors: Pentland Christopher H. , Itsekiri Endurance , Al Mansoori Saleh K. , Iglauer Stefan , Bijeljic Branko , Blunt Martin J.
Published: March 2010

We measure the trapped nonwetting-phase saturation as a function of initial saturation in sandpacks. The application of the work is for carbon dioxide (CO2) storage in aquifers, where capillary trapping is a rapid and effective mechanism to render the injected fluid immobile: The CO2 is injected into the formation followed by chase-brine injection or natural groundwater flow that displaces and traps it. Current models to predict the amount of trapping are based on experiments in consolidated media; while CO2 is likely to be injected at depths greater than approximately 800 m to render it supercritical, it may be injected into formations that tend to have a higher porosity and permeability than deep oilfield rocks. We use analog fluids—water and refined oil—at ambient conditions. The initial conditions are established by injecting oil into vertical or horizontal sandpacks 0.6 m long at different flow rates and then allowing the oil to migrate under gravity. The packs are then flooded with water. The columns are sliced, and the residual saturation is measured with great accuracy and sensitivity by gas chromatography (GC). This method allows low saturations to be measured reliably. The trapped saturation initially rises linearly with initial saturation to a value of approximately 0.13, followed by a constant residual as the initial saturation increases further. This behavior is not predicted by the traditional Land (1968) model but is physically consistent with poorly consolidated media where most of the larger pores can be invaded easily at relatively low saturation and there is, overall, relatively little trapping. The best match to our experimental data is achieved with the Aissaoui (1983) and the Spiteri et al. (2008) trapping models.
Use of X-Ray CT to Measure Pore Volume Compressibility of Shaybah Carbonates
Authors: Siddiqui Shameem , Funk James J. , Al-Tahini Ashraf M.
Published: March 2010

The Lower Cretaceous Shu'aiba formation (Shaybah field) in southeastern Saudi Arabia is a heterogeneous carbonate formation with various facies because of diagenetic alteration of the original rock fabric. Preliminary laboratory rock-mechanics studies indicated that the Shu'aiba carbonates are mechanically weak, with the majority of the rocks tested yielding very low strength values (less than 3,000 psi) when compared to samples from other carbonate reservoirs (Salamy and Finkbeiner 2002). On the basis of laboratory-derived rock-strength data from triaxial tests, the formation appears to behave in a plastic manner that strengthens the wellbore. To understand the stress behavior of the Shaybah rocks better, a set of pore volume compressibility tests was conducted in which the changes taking place within the samples were observed and quantified using an X-ray computerized-tomography (CT) scanner. A new technique involving dual-energy CT scanning was used to obtain the pore volume compressibility values, which were compared against the conventional triaxial-cell-generated data and published results by Harari et al. (1995) on cores taken from the same reservoir. Although the magnitude of the pore volume compressibility was the same between different setups, visual data showed some interesting behavior of the Shaybah cores including movement of grains in an irreversible manner even for a relatively low imposed effective stress of 2,000 psi. Some of the advantages of the new CT-based analysis technique include the generation of multiple pore volume compressibility curves from the same plug (a band of data, each at a different slice location), the "visualization" of the changes, the possibility of using either hydrostatic or triaxial cells to make the test more case-specific, and the possibility of measuring permeability under different stress conditions before, during, and after the test.
Modeling Foam Displacement with the Local-Equilibrium Approximation: Theory and Experimental Verification
Authors: Chen Q.. , Gerritsen M.G.. G. , Kovscek A.R.. R.
Published: March 2010

The gas-mobility-control aspects of foamed gas make it highly applicable for improved oil recovery. Gas-bubble size, often referred to as foam texture, determines gas-flow behavior in porous media. A population-balance model has been developed previously for modeling foam texture and flow in porous media. The model incorporates pore-level mechanisms of foam-bubble generation, coalescence, and transport. Here, we propose a simplified foam model to reduce computational costs. The formulation is based on the assumption of local equilibrium of foam generation and coalescence and is applicable to high- and low-quality foams. The proposed foam model is compatible with a standard reservoir simulator. It provides a potentially useful, efficient tool to predict foam flows accurately at the field scale for designing and managing foamed-gas applications.

There are three main contributions of this paper. First, foam-displacement experiments in a linear sandstone core are conducted. A visualization cell is employed to measure the effluent foam-bubble sizes for a transient flow as well as to estimate the in-situ foam-bubble sizes along the length of the core during steady-state flow. These appear to be the first measurements of foam-bubble texture in the entrance region of a core. Additionally, the evolution of aqueous-phase saturation is monitored using X-ray computed tomography (CT), and the pressure profile is measured by a series of pressure taps. Second, the population-balance representation of foam generation by gas-bubble snap-off is modified to extend the capability of the population-balance approach to predict foam-flow behaviors in both the so-called high-quality and low-quality regimes. Third, a simplified population-balance model is developed and implemented with the local-equilibrium approximation. Good agreement is found between the experimental results and the predictions of the simplified model, with a minor mismatch in the entrance region.
An Approach for Characterization and Lumping of Plus Fractions of Heavy Oil
Authors: Rodriguez I.. , Hamouda A.A.. A.
Published: March 2010

Heavy-oil fluids contain large concentrations of high-molecular-weight components, including a large content of the plus fractions, such as C7+.

Different approaches have been developed to characterize the petroleum plus fractions to improve prediction of the pseudocomponents properties by equations of state (EOSs).

A method is developed in this work to split the plus fraction into single carbon numbers (SCN), generating the mole fraction and the respective molecular weight. The developed method is based on the relationships between three-parameter gamma (TPG) distribution, experimental mole fraction, molecular weight, and SCN data obtained from the literature and industrial contacts. TPG is used to fit the trend of the compositional analysis. The characterized mole distribution as a function of SCNs is generated by integrating the TPG between the limiting molecular weights (LMw). The limiting molecular weights are determined simultaneously during the integration process by fitting the characterized and experimental mole fractions.

The developed method is easy to use. In addition, the approach is not dependent on the assumption that only normal carbon numbers exist in the composition resulting on fixed molecular weights for each single carbon number.

There are several correlations generated to predict physicochemical properties as a function of SCNs. Those correlations have been originally developed to work with light oil. Our approach is combined with some of the correlations and is tested for heavy-oil samples to identify the ranges in which they can be applied. Two lumping schemes are used to group the SCNs into pseudocomponents. The properties for each pseudo-component in this work are used to predict pressure/volume/temperature (PVT) data, constant volume depletion, using the Peng-Robinson EOS (PR-EOS), and the PVTP™ commercial simulator.
An Innovative Methodology for Designing Cement-Sheath Integrity Exposed to Steam Stimulation
Authors: Garnier A.. , Saint-Marc J.. , Bois A.-P.. -P. , Kermanac'h Y..
Published: March 2010

Heavy-oil production is one of the new challenges the oil and gas industry faces today, with trillions of barrels of reserves around the planet. To extract heavy oils, the viscosity has to be reduced to gain mobility and start the oil flowing. Of all the possible techniques, steam stimulation is, today, the most promising.

Steam is injected through the well down to the reservoir to warm it to a temperature of up to 250°C, inducing extreme thermal stresses in the well (especially when the temperature gradient through its components is maximum, as it is during initial steam injection or during workover when the well has to be quickly cooled down and heated up again to restart production rapidly).

To avoid zonal-isolation failure and steam release at the surface, new rules need to be considered in designing the barriers of a well exposed to steam stimulation, especially in very shallow fields. Where conventional rules may be applied for casing design, pioneering rules should be considered for designing the cement sheath.

This paper presents an innovative methodology for designing robust cement sheaths in very shallow conditions. First, stresses in the field are assessed with a rock-mechanics simulation. Then, the thermal gradient in the well components during the heating process is evaluated with a thermal simulation of the well. Both results are entered into Total's dedicated software to determine the mechanical properties the cement should have to withstand the thermal stresses. Different cement systems from service companies are evaluated in a cell, reproducing the field conditions to validate the simulation results.

This methodology was applied successfully to the Joslyn field wells, in Canada, where a resilient cement system with low Young's modulus and high tensile strength was selected and pumped. Because the results were positive, the methodology has been extended to other Total fields around the world where steam simulation is being considered.
A New Algorithm for Rachford-Rice for Multiphase Compositional Simulation
Authors: Okuno R.. , Johns R.T.. T. , Sepehrnoori K..
Published: March 2010

Flash calculations for use in compositional simulation are more difficult and time-consuming as the number of equilibrium phases increases beyond two. Because of its complexity, many simulators do not even attempt to incorporate three or more hydrocarbon phases, even though such cases are important in many low-temperature gasfloods or for high temperatures where hydrocarbons can partition into water. Multiphase flash algorithms typically use successive substitution (SS) followed by Newton's method. For NP-phase flash calculations, (NP–1) Rachford-Rice (RR) equations are solved in every iteration step in SS and, depending on the choice of independent variables, in Newton's method. Solution of RR equations determines both compositions and amounts of phases for a fixed overall composition and set of K-values. A robust algorithm for RR is critical to obtain convergence in multiphase compositional simulation and has not been satisfactorily developed, unlike the traditional two-phase flash. In this paper, we develop an algorithm for RR equations for multiphase compositional simulation that is guaranteed to converge to the correct solution independent of the number of phases for both positive and negative flash calculations.

We derive a function whose gradient vector consists of RR equations. This correct solution to the RR equations is formulated as a minimization of the nonmonotonic convex function using the independent variables of (NP–1) phase mole fractions. The key to obtaining a robust algorithm is that we specify nonnegative constraints for the resulting equilibrium phase compositions, which are described by a very small region with no poles. The minimization uses Newton's direction with a line-search technique to exhibit superlinear convergence. We show a case in which a previously developed method cannot converge while our algorithm rapidly converges in a few iterations. We implement the algorithm both in a standalone flash code and in UTCOMP (Chang et al. 1990), a multiphase compositional simulator, and show that the algorithm is guaranteed to converge when a multiphase region exists as indicated by stability analysis.
Enhanced Oil Recovery Pilot Testing Best Practices
Authors: Teletzke G.F.. F. , Wattenbarger R.C.. C. , Wilkinson J.R.. R.
Published: March 2010

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

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

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

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

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

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

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

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

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

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

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

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.
Steam Flooding of Naturally Fractured Reservoirs: Basic Concepts and Recovery Mechanisms
Authors: Mollaei A. , Maini B.
Published: March 2010

Abstract

A review of important issues in steam injection in naturally fractured reservoirs (NFRs) is presented. The effect of temperature on physical properties of crude oils and rocks and the thermo-chemical alteration of crude oil are discussed.

The recovery of oil from NFRs can be modelled as a two step process: first the oil is expelled from the matrix blocks through mechanisms that impose a pressure gradient within each matrix block and then it is swept through the fracture network to a production well by mechanisms that impose a pressure gradient within the fracture network. The recovery mechanisms associated with steam injection in NFRs and their characteristic times are presented. The most important recovery mechanism in matrix blocks is differential thermal expansion between oil and the matrix pore volume and the strongest mechanism in fracture network is the reduction of viscosity ratio (µo/µw). The matrix oil recovery mechanisms are relatively independent of oil gravity, making steam an equally attractive recovery process in fractured light and heavy oil reservoirs.

The mechanism and impact of CO2 generation during steam injection in carbonate reservoirs are discussed. The rate of CO2 generation is controlled by the rate of heat conduction from fracture into the matrix. For a specific reservoir the rate of heat conduction is a function of temperature and injection rate of steam and these can be optimized to make use of the in situ generated CO2.

Introduction

Heavy oil in naturally fractured carbonate reservoirs is an important resource, which accounts for one-third of total heavy oil worldwide. Many fractured reservoirs in the Middle East, former Soviet Union and Canada are candidates for thermal heavy oil recovery. Steam injection processes, which have been used extensively to recover heavy oil from non-fractured reservoirs, were not applied to fractured reservoirs until recently. This was primarily based on the belief that the injected steam would bypass the oil through the fractures and would be ineffective in recovering the oil. However, the results of experimental, theoretical and pilot tests which have appeared in the literature since early 1980s, show the feasibility of heavy oil recovery from fractured reservoirs using steam injection.
Numerical Simulation of In-Situ Combustion Experiments Operated Under Low Temperature Conditions
Authors: Sequera B. , Moore R.G. , Mehta S.A. , Ursenbach M.G.
Published: March 2010

Abstract

During in-situ combustion (ISC) processes, different chemical reactions occur depending on the temperature level. In heavy oils and bitumens, low temperature oxidation (LTO) reactions dominate below 300ºC, increasing the density and viscosity and producing coke which could prevent the success of ISC. Above 350ºC, combustion reactions dominate, known as high temperature oxidation (HTO), producing carbon oxides and water. Numerical models tend to include only thermal cracking and HTO reactions, as LTO reactions are not well understood. In the present work, ISC experiments operated under LTO were simulated, using Saturates, Aromatics, Resins and Asphaltenes (SARA) fractions to characterize the Athabasca bitumen. Concentration profiles and coke deposition for individual temperatures were matched for isothermal experiments from 60ºC to 150ºC. Based on these results, ramped temperature oxidation (RTO) experiments were then modelled, incorporating the heat of reaction at LTO. Different reaction models were studied to match temperature profiles along the reactor, oxygen consumption, coke formation and fluids production. This research will greatly increase the understanding of LTO reactions occurring in Athabasca bitumen during ISC and contribute to the creation of a reliable numerical model that predicts ISC performance under ideal (HTO) and, importantly, non-ideal (LTO) temperature conditions.

Introduction

ISC is a promising but complex oil recovery process in which thermal energy is generated inside the reservoir owing to combustion reactions between the heaviest fractions of the oil and an injected oxygen containing gas. For heavy oils and bitumens, ignition temperatures above 350°C are required to promote the combustion reactions (HTO). At lower temperatures, other types of reactions predominate, involving the addition of oxygen to the bitumen, producing heavier oxidized compounds. The LTO reactions are detrimental to oil production; hence, ISC processes are designed to operate under the high temperature combustion regime (HTO). However, LTO reactions occur if the air flux becomes too low to sustain the combustion reactions, leading to lower-than-estimated production yields. It has been proven in laboratory experiments that oil recovery is considerably reduced when LTO reactions occur to some extent, compromising the success of the ISC.