The purpose of this paper is to provide a comprehensive presentation and interpretation of the Ensemble Kalman Filter (EnKF) and its numerical implementation. The EnKF has a large user group, and numerous publications have discussed applications and theoretical aspects of it. This paper reviews the important results from these studies and also presents new ideas and alternative interpretations which further explain the success of the EnKF. In addition to providing the theoretical framework needed for using the EnKF, there is also a focus on the algorithmic formulation and optimal numerical implementation. A program listing is given for some of the key subroutines. The paper also touches upon specific issues such as the use of nonlinear measurements, in situ profiles of temperature and salinity, and data which are available with high frequency in time. An ensemble based optimal interpolation (EnOI) scheme is presented as a cost-effective approach which may serve as an alternative to the EnKF in some applications. A fairly extensive discussion is devoted to the use of time correlated model errors and the estimation of model bias.

The Ensemble Kalman Filter: Theoretical formulation and practical implementation

1: Magnetic Particles: Preparation, Properties and Applications: M. Ozaki. 2: Maghemite (gamma-Fe2O3): A Versatile Magnetic Colloidal Material C.J. Serna, M.P. Morales. 3: Dynamics of Adsorption and Oxidation of Organic Molecules on Illuminated Titanium Dioxide Particles Immersed in Water M.A. Blesa, R.J. Candal, S.A. Bilmes. 4: Colloidal Aggregation in Two-Dimensions A. Moncho-Jorda, F. Martinez-Lopez, M.A. Cabrerizo-Vilchez, R. Hidalgo Alvarez, M. Quesada-PMerez. 5: Kinetics of Particle and Protein Adsorption Z. Adamczyk.

Surface and Colloid Science

With the decline in oil discoveries during the last decades it is believed that EOR technologies will play a key role to meet the energy demand in years to come. This paper presents a comprehensive review of EOR status and opportunities to increase final recovery factors in reservoirs ranging from extra heavy oil to gas condensate. Specifically, the paper discusses EOR status and opportunities organized by reservoir lithology (sandstone and carbonates formations and turbiditic reservoirs to a lesser extent) and offshore and onshore fields. Risk and rewards of EOR methods including growing trends in recent years such as CO2 injection, high pressure air injection (HPAI) and chemical flooding are addressed including a brief overview of CO2-EOR project economics.

Enhanced Oil Recovery: An Update Review

[1] Relative permeabilities are the key descriptors in classical formulations of multiphase flow in porous media. Experimental evidence and an analysis of pore-scale physics demonstrate conclusively that relative permeabilities are not single functions of fluid saturations and that they display strong hysteresis effects. In this paper, we evaluate the relevance of relative permeability hysteresis when modeling geological CO2 sequestration processes. Here we concentrate on CO2 injection in saline aquifers. In this setting the CO2 is the nonwetting phase, and capillary trapping of the CO2 is an essential mechanism after the injection phase during the lateral and upward migration of the CO2 plume. We demonstrate the importance of accounting for CO2 trapping in the relative permeability model for predicting the distribution and mobility of CO2 in the formation. We conclude that modeling of relative permeability hysteresis is required to assess accurately the amount of CO2 that is immobilized by capillary trapping and therefore is not available to leak. We also demonstrate how the mechanism of capillary trapping can be exploited (e.g., by controlling the injection rate or alternating water and CO2 injection) to improve the overall effectiveness of the injection project.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1029/2005WR004806

Impact of relative permeability hysteresis on geological CO2 storage

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-brinerock 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 4 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 Ca. Injection of a low saline fluid, which promotes desorption of Ca, will create a local increase in pH close to the brine-clay interface because Ca 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 Ca 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. Introduction A great number of laboratory tests by Morrow and co-workers (Tang and Morrow, 1999a; Tang and Morrow, 1999b; Zhang and Morrow, 2006; Zhang et al., 2007b) and also by researchers at BP (Lager et al., 2007; Webb et al., 2005a; Webb et al., 2005b) have confirmed that enhanced oil recovery can be obtained when performing a tertiary low salinity waterflood, with salinity in the range of 1000-2000 ppm. Based on 14 tests from different sandstone reservoirs, Lager et al. (Lager et al., 2007) have reported that the average increase in recovery was about 14%. The laboratory observations have even been confirmed by single well tests performed in an Alaskan reservoir (Lager et al., 2008b). As increasing amounts of laboratory experiment results have been published in the last decade, various suggestions of the mechanism behind the low salinity process have appeared. Unfortunately, none of the suggested mechanisms have so far been generally accepted as the “true” mechanism. The reason is that many parameters linked to the rock, to the reservoir fluids (oil and brine), and to the injection fluid are involved. In order to give the reader a good background to understand the proposed mechanism in this paper, a list of the accepted experimental conditions is given, followed by a short recap of the previously suggested mechanisms. Conditions for low salinity effects The listed conditions for low salinity effects are mostly related to the systematic experimental work by Tang and Morrow (Tang and Morrow, 1999a), but some points has also been taken from the work by BP (Lager et al., 2007; Lager et al., 2008a).

/pdf/chemical-mechanism-of-low-salinity-water-flooding-in-1ir4r06nbq.pdf

Chemical Mechanism of Low Salinity Water Flooding in Sandstone Reservoirs

In recent years there has been an increasing interest in water-alternating-gas (WAG) processes, both miscible and immiscible. WAG injection is an oil recovery method initially aimed to improve sweep efficiency during gas injection. In some recent applications produced hydrocarbon gas has been re-injected in water injection wells with the aim of improving oil recovery and pressure maintenance. Oil recovery by WAG has been attributed to contact of unswept zones, especially recovery of attic or cellar oil by exploiting the segregation of gas to the top or accumulating of water towards the bottom. Since the residual oil after gas flooding is normally lower than the residual oil after water flooding, and three-phase zones may obtain lower remaining oil saturation, water-alternating-gas has potential for increased microscopic displacement efficiency. WAG injection, thus, can lead to improved oil recovery by combining better mobility control and contacting unswept zones, and also leading to improved microscopical displacement. This study is a review of the WAG field experience as it is found in the literature today from the first reported WAG in 1957 in Canada and up to new experience from the North Sea. About 60 fields have been reviewed. Both onshore and offshore projects have been included, as well as WAG with hydrocarbon or non-hydrocarbon gases. Wellspacing is very different from onshore projects (where fine patterns often are applied) to offshore projects (well spacing in the order of 1000 meters). For the fields reviewed, a common trend for the successful injections is an increased oil recovery in the range of 5-10 per cent of the OIIP. Very few field trials have been reported unsuccessful, but operational problems are often comment Though, the injectivity and production problems are generall not detrimental for the WAG process, special attention been given to breakthrough of injected phases (water or gas Improved oil recovery by WAG is discussed as influenced b rock type, injection strategy, miscible/immiscible gas, an well spacing.

Review of wag field experience

Recently, low salinity brine injection has been given a great interest as a technique for enhanced oil recovery (EOR) by waterflooding. Varying experimental results have been reported in the literature, from many promising results to limited or no effects of low salinity. The application of low salinity water in combination with other established EOR processes (e.g., surfactant flooding and polymer flooding) is of great interest. The combined processes involve dampening capillarity to avoid trapping of mobilized oil, reducing residual oil saturation (Sor), and altering frontal stability and sweep. In this article, we address the questions of timing of LS injection and the added benefit of polymer injection. Secondary-mode (at initial water saturation) and tertiary-mode (after seawater residual oil saturation) low salinity waterflooding experiments were performed on outcrop Berea sandstone core material. The main results are the oil recovery efficiencies of these two different flooding modes. These results...

Enhanced Oil Recovery (EOR) by Combined Low Salinity Water/Polymer Flooding

Foam for Gas Mobility Control in the Snorre Field: The FAWAG Project

The concept of surfactant flooding has long been recognized as a promising supplement to water-based enhanced oil recovery methods. In recent years, core displacement experiments performed on clastic rock samples using low salinity brine as injection fluid have proven to give a moderate increase in crude oil recovery. This paper presents a new hybrid EOR process where the effect of low salinity brine injection is combined with surfactant flooding. An anionic surfactant formulation was selected to give low interfacial tension (IFT) in a low salinity environment containing 0.50 wt % NaCl. The surfactant forms Winsor type I microemulsion at this salinity. Improved surfactant solubility and reduced adsorption or retention is among the advantages of using surfactant at low salinity conditions. This paper reports core flood experiments performed on outcrop sandstone cores using crude oil as the oil phase. Results show high oil recovery of more than 90% of original oil in place (OOIP) when surfactant is used in ...

https://pubs.acs.org/doi/pdf/10.1021/ef101501b

Combined Low Salinity Brine Injection and Surfactant Flooding in Mixed−Wet Sandstone Cores

Summary Multiphase flow involving saturation oscillations should be modeled with history-dependent, relative permeability functions. Earlier approaches have been based on two-phase flow. The main assumptions have been that the imbibition process is reversible. Moreover, scanning curves were developed only for saturations between some extreme values. Several tertiary oil recovery processes have shown cycle-dependent hysteresis for relative permeability. When saturation oscillations occur during three-phase flow such as water alternating gas (WAG), the two-phase hysteresis models will generally not be able to describe relative permeabilities obtained from corefloods. For three-phase flow, local hysteresis effects may also be important. New relative permeability representations that account for local hysteresis effects are presented. Hysteresis models for both wetting and nonwetting phase permeabilities have been developed. The new models account for reduced mobility and irreversible hysteresis loops during threephase flow. The models depend on the initial saturation at the start of the given process. An algorithm is presented for implementing the nonwetting phase hysteresis model in a numerical simulator. The new three-phase models use experimental wetting and nonwetting relative permeabilities as input, and knowledge of relations between maximum nonwetting saturation and trapped nonwetting

/pdf/methodology-for-numerical-simulation-with-cycle-dependent-2gs34c8fi8.pdf

Arne Skauge

Papers

Review of wag field experience

Enhanced Oil Recovery (EOR) by Combined Low Salinity Water/Polymer Flooding

Foam for Gas Mobility Control in the Snorre Field: The FAWAG Project

Combined Low Salinity Brine Injection and Surfactant Flooding in Mixed−Wet Sandstone Cores

Methodology for Numerical Simulation With Cycle-Dependent Relative Permeabilities