bluuebunny/crossref_metadata_2025_split huggingface dataset:
Limitations of Current MOC (Method of Characteristic) Methods to Predict MMPs for Complex Gas/Oil Displacements
Authors: Ahmadi Kaveh , Johns Russell T. , Mogensen Kristian , Noman Rashed 
Published: July 2010

Abstract
An accurate minimum miscibility pressure (MMP) is one of the key factors in miscible gas flood design. There are a variety of experimental and analytical methods to determine the MMP, but the most reliable methods are slim-tube experiments, 1-D slim-tube simulations, mixing-cell models, and the key tie-line approach using method of characteristics (MOC). Direct comparisons of all these methods generally agree well, but there are cases where they do not. No explanation has yet been given for the anomalies, although the MMP is critically important to recovery.
The focus of this paper is to explain when current MOC results may not be reliable and how to identify when this is the case. We demonstrate using fluid characterizations from Middle Eastern oils that the MMPs using the MOC method can be over 6500 psia greater than those calculated using a recently developed mixing-cell method. The observed differences in the MMP increase substantially as the API gravity of the oil decreases. We show that the key tie lines determined using MOC methods do not control miscibility for such cases. We explain the reasons for these differences using simplified pseudo-ternary models and show how to determine when an error exists. We also offer several ways to correct the MMP predictions using the MOC for these complex gas/oil displacements.
Interpreting Single Well Chemical Tracer Tests
Authors: Jerauld Gary R. , Mohammadi Hourshad , Webb Kevin J. 
Published: July 2010

Abstract
Single Well Chemical Tracer Tests (SWCTT) are widely used to estimate the remaining oil saturation after waterflooding (Sorw) and enhanced oil recovery including low salinity waterflooding. SWCTT have the advantage of being a more direct measure of Sorw than logs and unlike cores do not have the uncertainty of maintaining or restoring wettability and samples more reservoir rock. Interpretation of the test is often superficial, lacking a full description of physical processes involved and proper uncertainty analysis. This paper analyses SWCTTs from high and low salinity waterflooding, explains what is necessary to model the tests, demonstrates rigorous uncertainty analysis, and shows the value of designing tests with simulation.
Simulation procedures involve finding multiple history matches to the observed tracer production. Parameters affecting tracer production such as Sorw, mechanical dispersivity, hydrolysis reaction rate, number of layers and the amount of fluid injected and produced for each layer are adjusted to get the best fit. Nonstandard aspects of SWCTT must also be modeled. Because Sorw is sensitive to the ester partitioning coefficient which in turn is sensitive to salinity and temperature, injection of water with a lower temperature than the reservoir impacts interpretation. In one example, if the temperature variation is not accounted for the error in Sorw is 3 su.
Each SWCTT has its own characteristics which often appear to be different even in repeat tests on the same well. Apart from the common variables, other variables often must be introduced to get a good history match. In most cases, the shape of the tracer profiles cannot be satisfactorily matched with a single layer and layers with different levels of irreversibility must be added to match the shape. The well bore volume is sometimes varied. In repeat tests on the same well, constraining the interpretations to have the same layering and not increasing Sorw can reduce uncertainty and improve interpretation. In one case, a one-layer analysis shows no benefit but more detailed analysis with 3 layers indicates an incremental recovery of 12% PV, depending on the assumptions about well bore volume; the best fit overall indicated 2% PV.
Multiphase Fluid Flow Simulation of Heavy Oil Recovery by Electromagnetic Heating
Authors: Carrizales Maylin A. , Lake Larry W. , Johns Russell T. 
Published: July 2010

Abstract
Electromagnetic (EM) heating, also called high-frequency heating, generates EM waves through an antenna located inside a wellbore and parallel to the reservoir sand-face. The EM energy heats the reservoir from within, causing oil viscosity to lower and oil production to increase. Recent studies (Carrizales et al. 2008) showed that oil rate can be increased with the application of EM heating for single-phase radial flow. No simulations results or detailed modeling studies have yet been published that completely model the complex interactions of EM energy and multiphase flow.
This paper presents a multiphase, two-dimensional radial model that describes the three-phase flow of water, oil, and steam and heat flow in a reservoir within confining formations. The model accounts for the appearance and/or disappearance of a phase, and uses the variation in temperature and water saturation to continuously update the EM heating rate. A single well is used to locate the EM source, and also to produce oil. Gravity effects and vertical heat loss into the confining layers are included. This model allows determining the temperature distribution and the productivity improvement from EM heating when multiple phases are present. This model will be useful to predict the recovery of heavy oil by EM heating where conventional steam injection is not attractive.
To solve the model we used Lagrange-quadratic finite elements in the environment provided by COMSOL Multiphysics and its partial differential equations (PDE) application. Several simulations were made for hypothetical reservoirs with different fluid and rock properties. Special attention is on reservoirs with characteristics for which steam injection does not look attractive or feasible. Results show the feasibility of conducting EM heating based on the power source and frequency used to maintain an optimum absorption coefficient and to obtain higher production rates avoiding excessive power consumption. Also, a comparison shows that cumulative oil production and recovery factor obtained by EM heating is better than what is achieved by cyclic steam stimulation (CSS), especially for thin payzones.
Experimental Study of Foam Flow in Fractured Oil-wet Limestone for Enhanced Oil Recovery
Authors: Haugen Å. , Fernø M. A. , Graue A. , Bertin H. J. 
Published: July 2010

Abstract
The use of foam to increase oil recovery by reducing the gas mobility during gas injection in heterogeneous reservoirs with permeability variations is a proven EOR technology. The use of foam for fracture permeability reduction in fractured reservoirs is less studied. In this work laboratory experiments using foam to reduce fracture transmissivity and improve the matrix sweep in highly fractured, low permeable, oil-wet limestone are reported. Oil recovery either by individual water-, surfactant-, or gas injection exhibited low recovery, less than 10%OIP, with oil recovered predominately from the fractures. Oil recovery was significantly improved by simultaneous injection of surfactant and gas to generate foam in the fracture network and thus divert flow to the oil saturated matrix. Two foam injection schemes were tested: 1) co-injection of surfactant and gas in the fracture for in-situ foam generation, and 2) pre-generated foam injection. In-situ foam generation in the smooth-walled fractures was weak and not sufficient to divert fluids from the fractures and into the matrix. Injection of stable, pre-generated foam caused an increase in the differential pressure and diverted fluid to the matrix, yielding a significant increase in oil recovery, 80% OIP was receverd at high pore volumes injected.
Squeeze Related Well Productivity Impairment Mechanisms & Preventative/Remedial Measures Utilised: Norwegian Continental Shelf
Authors: Fleming N. , Ramstad K. , Mathisen A.-M. , Selle O. M. , Tjomsland T. , Fadnes F. H. 
Published: July 2010

Abstract
Squeezing is routinely employed by Statoil as a means of maintaining well productivity and avoiding safety issues related to downhole safety valve scaling. In the majority of cases, squeezing maintains well production through minimisation of scale related downtime. However, it has been observed occasionally by Statoil that the benefits of scale prevention by squeezing can be outweighed by the detrimental impact on well productivity. While there have been several articles covering specific elements of a squeeze operation that have affected well productivity, little has been published that attempts to completely describe squeeze related, production impairment mechanisms. This paper will aim to address this gap by demonstrating how squeezing, in some cases, can have an adverse impact on well productivity and highlight the remedial or preventative methods that have been utilised.
A review of the squeeze related, production impairment mechanisms from Statoil operated fields show that they can be related to near wellbore formation, alteration in the reservoir production characteristics or completion design. Physical formation damage mechanisms include Squeezing of sensitive reservoirs (fines mobilisation and clay swelling)Scaling of production intervals due to incorrect inhibitor placementViscosified inhibitor formation damageDamage related to precipitation squeezesIncreased sand production after squeezing
Liquid formation damage mechanisms include Squeeze related relative permeability alteration causing increased water cut and reduced oil rates.Water blocks and emulsion formation due to squeezing of an aqueous treatment into an oil producing or water sensitive interval.
Other examples of squeeze related productivity impairment are screen and gravelpack blockage while an indirect effect are lift problems after squeezing in wells with depleted reservoir pressure. In all instances, the economic costs of lost production can far exceed those of actually performing the squeeze. Case histories will be used to illustrate the productivity impairment mechanisms and methods used to overcome these along with lessons learned.
Chemical Mechanism of Low Salinity Water Flooding in Sandstone Reservoirs
Authors: Austad Tor , RezaeiDoust Alireza , Puntervold Tina 
Published: July 2010

Abstract
Both laboratory and single well field tests have documented that enhanced oil recovery can be obtained from sandstone reservoirs by performing a tertiary low saline waterflood. Due to the complexity of the crude oil-brine-rock interactions, the mechanism behind the low saline EOR process has been debated in the literature for the last decade. Both physical and chemical mechanisms have been proposed, but it appears that none of the suggested processes has so far been generally accepted as the main contributor to the observed low salinity EOR effect. Based on published data and new experimental results on core flooding, effects of pH and salinity on adsorption of acidic and basic organic components onto different clay minerals, clay properties like ion exchange capacity and selectivity, and oil properties, a new chemical mechanism is suggested, which agrees with documented experimental facts. At reservoir conditions, the pH of formation water is about 5 due to dissolved acidic gases like CO2 and H2S. At this pH, the clay minerals, which act as cation exchange material, are adsorbed by acidic and protonated basic components from the crude oil, and cations, especially divalent cations from the formation water, like Ca2+. Injection of a low saline fluid, which promotes desorption of Ca2+, will create a local increase in pH close to the brine-clay interface because Ca2+ is substituted by H+ from the water. A fast reaction between OH- and the adsorbed acidic and protonated basic material will cause desorption of organic material from the clay. The water wetness of the rock is improved, and increased oil recovery is observed.
To observe low salinity EOR effects in sandstones, a balanced initial adsorption of organic components and Ca2+ onto the clay is needed. Both the adsorption capacity and the pH-window for adsorption/desorption of organic material is somewhat different for various types of clay minerals. A detailed knowledge of the chemical mechanism behind the low saline EOR process together with information on formation brine composition, oil properties and type of clay material present, will make it possible to evaluate the potential for increase in oil recovery by a low salinity waterflood.
Development of Improved Hydrocarbon Recovery Screening Methodologies
Authors: Dickson Jasper L. , Leahy-Dios Alana , Wylie Philip L. 
Published: July 2010

Abstract
This paper describes a novel improved hydrocarbon recovery (IHR) screening methodology capable of (1) screening and prioritizing a large number of reservoirs for various IHR processes and (2) generating preliminary flowstreams through generic sector modeling and proxy simulation. This methodology enables quick screening for a variety of EOR techniques using reservoir rock/fluid properties and technical/economic screening criteria, and quantitatively ranks the EOR options. It also provides the means to complete a first-pass estimate of reservoir performance by applying case-specific performance curves to run facility level simulations. It has been thoroughly tested for various fields where different EOR strategies were or are being implemented, and the results are in good agreement with published data. This methodology helps identify potential IHR opportunities, enabling operators to quickly test the validity and relative merits of IHR for any field or reservoir.
Modification of Capacitance-Resistive Model for Estimating Waterflood Performance
Authors: Chen Huan , Zhang Zhihong , Sun Wenjie , Li Kewen 
Published: July 2010

AbstractOne of the important parameters in capacitance-resistive model (CRM) for the prediction of production performance is fij, representing the fraction of injection rate of injector i flowing toward producer j. However fij was usually assigned to unity when a reservoir is represented by a single producer and a single injector as a tank. We found that this might not be true in many cases. In this study, the above assumption of unity fij was relaxed in the case of lump reservoir model (tank model). Another problem in applying CRM is the poor accuracy of the match and prediction of oil production. In this study we modified the CRM for matching and predicting oil production with greater accuracy than the existing fractional flow model. Production data from chosen oil reservoirs were analyzed using both existing and modified approaches and the results were compared. The results showed that the modified CRM approach could fit the production performance better than the existing CRM in many cases. This study demonstrated that the assumption of unity fij could be removed in the case of lump reservoir model. The physical significance behind this was proposed and explained. The results and analysis demonstrated that the accuracy of the modified oil production model was significantly greater than the existing fractional flow model in many cases.
Selective Polymer Treatments Improve Oil Recovery in Five Mature Southern Oklahoma Waterfloods
Authors: Portwood J. T. , Lackey Scott H. , Abel Scott W. 
Published: July 2010

Abstract
The Healdton Field was discovered in 1913 and is located in Carter County, Oklahoma. A total of 8 units covering 8,160 acres were formed in the 1960's to waterflood a thick sequence of shallow sandstones that were deposited in an area that is 10 miles long and 3 miles wide. Today, 317,000 BW are injected into 350 wells to produce 2,200 BOPD + 324,000 BWPD from 800 wells. There are 2 units in the area that are not being waterflooded. Historically, injection profile logs and high water-cuts at producers have indicated that injected fluids have never been evenly distributed throughout the sands due to a large variation in permeability. In spite of using mechanical zone isolation techniques to improve vertical sweep, significant volumes of mobile oil trapped in lower permeability rock have been by-passed. The remaining mobile oil could not be economically recovered in a reasonable amount of time unless the injected fluids could be redistributed more uniformly throughout the sands in both the areal and vertical planes.
Since March 2006, a total of 56 water injection wells in 5 of the waterflood units have been treated with relatively large volumes of cross-linked polymer gel to improve the distribution of injection water, provide for better volumetric sweep efficiency, and higher oil recovery. Bullhead treatments blended in formation brine were custom designed for each candidate injection well. Novel treatment strategies had to be developed so that large polymer volumes could be injected in a field where well spacing is "tight" (2.5 – 5.0 acres) and where polymer breakthrough is possible. To date, a total of about 745,000 barrels of polymer gel have been injected.
The project has resulted in sharply higher oil production, lower WOR, and higher oil-cut percentage. Nearly 170,000 barrels of incremental oil have been recovered during the first 3.8 years of the project, and it is estimated that ultimate incremental recovery will approach at least 2.3 MMBO. Further, it is estimated that the treatments have added at least 10 years to the economic life of these 5 units at current oil prices. Although overall project economics have been very favorable, the lessons learned from this project will be used to more effectively apply the technology to other areas in this field and to other sandstone waterfloods in general.
General Strategy for Stability Testing and Phase-split Calculations in Two and Three Phases
Authors: Li Z. , Firoozabadi A. 
Published: July 2010

Abstract
Efficient and robust phase equilibrium computations have become a pre-requisite for successful large scale compositional reservoir simulations. When the initial estimate of equilibrium ratios is not available from previous simulation time step, the ideal strategy for the phase-split calculation is the use of stability testing. We present a general strategy for two-and three-phase split calculations based on reliable stability testing where we apply the quasi-Newton method with superlinear convergence rate. The Wilson correlation and new correlations are combined to provide the initial estimate of equilibrium ratios. In the phase-split calculation, the successive substitution iteration (SSI), General-Dominant-Eigenvalue (GDE), and Newton methods are combined. The SSI is only first-order and is generally used to provide the initial guess for the Newton method. The GDE update is adopted to accelerate the SSI. The Newton method has quadratic convergence rate and can locate the solution within a few iteration steps when the initial guess is close enough to the solution. Powerful features of the strategy are extensively tested by calculating the complicated phase envelops of four hydrocarbon fluids mixed with CO2 in single-, two-, and three-phase regions.
Improving Steam-Assisted Gravity Drainage Using Mobility Control Foams: Foam Assisted-SAGD (FA-SAGD)
Authors: Chen Q. , Gerritsen M. G. , Kovscek A. R. 
Published: July 2010

Abstract
Steam-assisted gravity drainage (SAGD) is a promising approach for recovering heavy and viscous oil. The success of SAGD relies on two key operations: uniform formation of the steam chamber along the full length of the injector, and effective control of steam breakthrough by sustaining a liquid level between the injector and producer (i.e. a steam trap). Intrinsic permeability heterogeneities typically lead to a partially-developed steam chamber and potentially low sweep efficiency that results in reduced oil production. The injectivity variability along the well also complicates the control of steam breakthrough. To overcome these difficulties, we propose the use of foamed steam. The feasibility of foam-assisted SAGD (FA-SAGD) is demonstrated numerically with a local-equilibrium foam simulator incorporating the physical mechanisms of foam generation, destruction, and transport. The model was validated previously. Simulation results show that strong foam is generated and accumulates in the interwell region. The presence of foamed steam helps to control steam breakthrough and yields better recovery performance per barrel of steam injected than conventional SAGD. Live steam production in simulations is reduced by a factor of 5. Consequently, cumulative oil production is increased by about 30% in comparison to cases without foam. Sensitivity analysis of the parameters describing foam indicate that the process is robust.
An Integrated Workflow for Chemical EOR Pilot Design
Authors: Moreau P. , Morvan M. , Rivoal P. , Bazin B. , Douarche F. , Argillier J.-F. , Tabary R. 
Published: July 2010

Abstract
After primary and secondary production of oil from a petroleum reservoir, more than half of the oil is often left in place. In order to improve the process displacement efficiency – so that one can recover some of this remaining capillary-trapped or water-by-passed oil –, it is necessary to apply enhanced oil recovery (EOR) techniques such as surfactant flooding, either Surfactant (S), Surfactant-Polymer (SP) or Alkaline-Surfactant-Polymer (ASP).
This paper describes a complete workflow for optimizing S, SP or ASP processes for chemical EOR. The workflow consists in successive steps: reservoir fluid and rock characterizations, formulation screening, core flood validation and simulation including sensitivity studies.
Formulation design is performed through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools. Objective of the formulation platform is to provide a robust formulation adapted to the variability of the reservoir conditions (temperature and salinity windows, oil composition). Data on brine compatibility, oil solubilization ratio and water-oil interfacial tension (IFT) are systematically provided. Adsorption measurements are conducted for the selection of the best formulations. Core flood experiments are performed to validate performances of selected chemical formulation(s) and define simulation input data. IFT measurements, adsorption data, capillary desaturation curves, and diphasic water-oil relative permeabilities are further used as input for simulations. A chemical EOR simulator (SaripCH software), specifically designed for ASP processes design, has been developed. After the lab study, pilot design is the next step towards the application of the S, SP or ASP process in the field. SaripCH simulator is used to evaluate the performances of the process at the reservoir scale.