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IOR 2009 - 15th European Symposium on Improved Oil Recovery
- Conference date: 27 Apr 2009 - 29 Apr 2009
- Location: Paris, France
- ISBN: 978-90-73781-60-3
- Published: 27 April 2009
64 results
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Key Success Factors for IOR/EOR Implementation
By V. A. BrockWith an average oil recovery efficiency in the industry of a little over 30%, meaning about 2/3 of the oil
originally in place in the world s reservoirs is left behind, the imperative to increase recovery is clear.
Today EOR accounts for only about 4% of the world s production, however projections by IEA and others
forecast the role of EOR to grow significantly in the coming years, to perhaps 20% by 2030. This kind of
growth will be a major challenge to achieve, requiring clear focus on addressing the technology tools and
other critical success factors required. This paper will explore these critical success factors, drawing upon
Shell and industry experiences in improved and enhanced recovery, with case examples.
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The Emlichheim Oilfield - 45 Years of EOR and No End
By M. DreierThe Emlichheim Oilfield is part of the cross-border anticline structure Schoonebeek-Emlichheim between
Germany and The Netherlands. The structure was discovered oil bearing in 1943 and brought on-stream
one year later on the German side. Due to its nature - bearing an medium-heavy crude - topics like
artificial lifting or pressure support by water injection were applied at a very early stage in field lift.
Primary and secondary recovery methods only had a scope to recover ~10-12% of STOIIP and field
production would go into a steep decline once water breakthrough would occur massively.
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EOR in BP – Making it Happen
Authors C. Reddick, D. Puckett, A. Cockin, T. Buikema, R. Choo, S. Mahmood and I. CollinsBP s current and future hydrocarbon portfolio contains a significant proportion of oil resources which are
the target of new EOR techniques being developed by BP to improve recovery beyond what is possible
with conventional methods. These techniques are focussing on improving both pore scale displacement as
well as sweep efficiency.
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New Viscoelastic Fluid for Chemical EOR
Authors M. Morvan, G. Degre, J. Leng, C. Masselon, J. Bouillot, A. Zaitoun and P. MoreauThe viscoelastic fluid is induced by wormlike micelles formed by self-assembled surfactants. The phase
diagram of the surfactant in pure water was established using a pervaporation-based microfluidic device
(Leng et al., PRL, 96, 2006). Isotropic wormlike micelles have been observed up to 12 % w/w. In a second
step, Particle Tracking Microrheology (PTM) was used to investigate the rheological properties of the fluid
for surfactant concentrations below 2% w/w in water. Viscosity at low surfactant concentrations (0.1% to
0.3 % w/w), T= 80°C, in synthetic sea water (3.9 % w/w TDS) and in sodium chloride (2 % w/w TDS) has
been recorded. Data shows that the viscosity is weakly dependent on brine concentration and evolves
between 3 and 15 mPa.s (shear rate equal 10 s-1), for surfactant concentrations between respectively 0.1%
to 0.3 % w/w.
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MIOR Displacement Mechanisms in Glass Micromodel
Authors M. Shabani Afrapoli, S. Ostvar, C. Crescente and O. TorsaeterMany studies on Microbial Improved Oil Recovery have demonstrated that bacteria have a positive effect
in regard to reduce the residual oil saturation. Possible mechanisms of IOR as a result of bacterial activity
are; interfacial tension reduction, change of wettability, gas production and conformance control through
selective blocking of the most permeable pore channels. Understanding which mechanisms allow bacteria
to increase oil recovery and how these mechanisms occur and interact is the key to better understand and
to get a clear insight into the complex MIOR processes.
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Pore Scale Modelling of Linked Polymer Solution (LPS) – A New EOR Process
Authors S. Fallah Bolandtaba, A. Skauge and E. MacKayThe paper describe the concept of developing a modeling tool for pore scale modeling of Linked Polymer
Solution (LPS) or Colloid dispersion gels (CDG). The linked polymer solutions consist of low
concentration of partially hydrolyzed Polyacrylamide polymer cross linked with alumina citrate which
may be used as EOR method after water or polymer flooding. Although the results from field trials are
very promising, the mechanism and the physics of LPS are not still well understood.
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The Potential of High Resolution Satellite Interferometry
Authors L. Petrat, U. Wegmüller, K. Zimmermann and I. Al QuseimiRising importance of using Enhanced Oil Recovery (EOR) in oil production also increased the demand for
monitoring related effects like surface movements. Over the last years land surface movement monitoring
using satellite Synthetic Aperture Radar (SAR) interferometry became operational. In the last year a new
generation of SAR satellites with high resolution modes and short revisit times was launched and
interferometric data series are available. This development reveals the potential for monitoring small-scale
and highly dynamic surface movements related to EOR more accurate than by using conventional systems.
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Advances in Understanding Thermally Assisted GOGD
Authors P. M. Boerrigter and J. J. van DorpThe connected fracture network in densely fractured reservoirs has a strong impact on reservoir
displacement mechanisms. Due to the high fracture permeability no significant pressure differentials
across oil bearing matrix blocks can be established to drive oil from matrix into the fracture. One has to
rely on natural mechanisms like capillary imbibition or gravity to recover oil from the matrix rock. Often
the matrix rock is oil-wet or mixed wet and only gravity drainage remains a feasible process. Usually,
however, permeabilities are low, <10 mDarcy, resulting in low gravity drainage production rates with high
remaining oil saturation and/or capillary holdup.
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Wetting Properties of Chalk – Impact of Water Soluble Acidic Material in Crude Oil
Authors S. Strand, S. J. F. Fathi, T. A. Austad and T. P. PuntervoldCarboxylic material present in the crude oil, quantified as acid number (AN), is believed to be the most
important wetting parameter for carbonates. The water wetness decreases as the AN increases. At high
temperature, seawater is able to displace some of the adsorbed carboxylic materials, and seawater
therefore acts as a wettability modifier causing increased oil recovery both by spontaneous imbibition and
by forced displacement. It has been documented that interactions between ions present in seawater, Ca2+,
Mg2+ and SO42-, and the chalk surface are responsible for the wettability modification. The properties of
the carboxylic material may have influence on the initial wetting conditions and also on the wettability
alteration process. In this paper we have extracted water soluble acids from a crude oil with high AN. The
original oil (AN=1.8 mgKOH/g) and the treated oil depleted in water soluble acids (AN=1.5 mgKOH/g)
were used to study wetting properties and oil recovery by spontaneous imbibition with chalk as the porous
medium. The water wetness appeared to be lower for the original oil compared to the treated oil. In a
spontaneous imbibition process with wettability modification at 110 °C, seawater imbibed faster into the
cores saturated with the treated oil containing no water soluble acids.
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Improved Spontaneous Imbibition of Water in Reservoir Chalks
Authors I. F. Fjelde and S. M. A. AasenAlteration of wettability to more water-wet and thereby improvement of spontaneous imbibition of water
during sea water injection, has been studied using reservoir core plugs from two fractured chalk fields.
Core plugs were prepared by removing easily accessible sulphate. The wettability conditions were
characterized using the sulphate wettability test. Spontaneous imbibition of water was studied using brines
with different ratios between formation water and sea water. The wettability and spontaneous imbibition
for reservoir core plugs and outcrop core plugs were compared.
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Chemical Effects on Chalk Weakning and Fracture Deformation
Authors R. Al Zadjali, Q. Fisher and C. A. GrattoniSteam injection is becoming increasingly used to enhance heavy oil production even in complex reservoirs
such as fractured carbonates. However, injecting steam into fractures has the potential to change reservoir
permeability because increasing the temperature causes the reservoir rock to expand potentially closing
fractures and condensed water may react with the reservoir rock; both processes may increase uncertainty
in predicting oil recovery from these reservoirs.
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Reservoir Surveillance Technologies for Thermal EOR Projects
Authors D. F. Hohl, J. Lopez, R. Bos and K. P. MaronShell has started to launch integrated data acquisition programs and to test automated methods for
optimizing injection and production schedules in thermal EOR projects. We present applications of a suite
of areal and well-based reservoir surveillance technologies to thermal hydrocarbon recovery in the
Canadian heavy-oil sands and the Middle East. These technologies include surface seismic, micro seismic,
downhole seismic, and are combined with forward and inverse modeling in an effort to improve reservoir
understanding and to optimize production.
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Prediction of Oil/Gas Saturation Variation with Time-lapse Seismic Elastic Parameter Inversion
More LessIt is well known that time-lapse seismic can improve the Oil or Gas recovery from existing reservoirs and
it has been taken as a powerful tool for reservoir management. It shows how a reservoir behavior changes
at different development times and provide valuable information for further development plan. In this
paper, a prediction method with ANN (artificial neural network) based on time-lapse seismic prestack
elastic parameter inversion is introduced to describe the oil or gas saturation variation and reservoir
pressure change.
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Joint Structural and Petrophysical History Matching of Stochastic Reservoir Models
Authors T. Schaaf and B. CoureaudHistory matching is an integral part of reservoir production forecasting and uncertainties quantification
workflows. One has to cope with the non-uniqueness issue as history matching is an ill-posed inverse
problem, due to a lack in constraints and data. Dealing with several history matched models is therefore
critical and assisted history matching tools are of great interest to speed up the process.
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Rock Fluid Interactions in Chalk with MgCl2 and Na2CI4 Brines with Equal Ionic Strength
Authors M. V. Madland, B. Zangiabadi, R. I. Korsnes, S. Evje, L. Cathles, T. G. Kristiansen and A. HiorthThe effect of the aqueous chemistry on the mechanical strength of chalk has been studied extensively at
the University of Stavanger. At high temperatures (~130°C) chalk exposed to seawater is significantly
weaker compared to chalk exposed to distilled water as considering the hydrostatic yield strength and the
following creep phase
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Pore-water Distribution from NMR to Study Water-induced Compaction in High-porosity Chalk
Authors M. Megawati, A. Hiorth, O. K. Siqveland, R. I. Korsnes, T. G. Kristiansen and M. V. MadlandHigh porosity chalk at full and partial saturation was isotropically loaded to 5 MPa, and beyond yield by
use of a standard Triaxial cell. We investigate the NMR response when chalk cores were loaded beyond
yield and compare with the result before yield. Both the CPMG and pulse field gradient sequence were
run, in order to measure the T1 and T2 relaxation, and the restricted diffusion. Measurements were
performed at fully and partial saturated (Sw < 9%) cores. The measurement of the restricted diffusion
coefficient gave limited information, because of limitations in the experimental equipment. The 1/T1,2
relaxation rate correlated with the deformation. The NMR signal from the partial saturated cores showed
no response to the applied stress level. The signal was dominated by two relaxation rates, which we argue
corresponds to the surface film (~10 nm) and non invaded pores (~0.1 μm). The fact that the partial
saturated cores showed no correlation with the applied stress level could be an indication that the forces
controlling the strength of the rock are of much shorter range than what we probe with the NMR machine.
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Multicomponent Transport Model at Core Scale for Microbial EOR Processes Modeling
Authors D. A. López-Falcón, M. A. Díaz-Viera and E. Luna-RojeroFate of microorganisms in porous media has very important applications in many branches of
environmental and petroleum science and engineering, like in the Microbial Enhanced Oil Recovery
(MEOR) processes, among others; however, concurrently it is a very complex and interacting phenomenon
mainly because microorganisms are living. Applying the systematic modeling approach to continuum
systems, we derive a model that include net flux of microorganisms and nutrients by convection and
dispersion, growth and decay rates of microorganisms, chemotactic movement and nutrient consumption,
adsorption of microorganisms and nutrients on rock grain surfaces, as well as desorption of
microorganisms. Porosity reduction due to cell and nutrient adsorption is considered. We implement the
model within a Finite Element Method. The numerical simulations reproduce results previously reported
elsewhere; moreover, we show the spatial-temporal distribution of microorganisms and nutrients along the
system and time. We point out the complementary role of the spatial-temporal distribution of components
with breakthrough curves to analyze the behavior of both fluent and adsorbed components.
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EOR Option for a Heterogeneous Carbonate Reservoirs with Complex Waterflood Performance
Authors S. K. Masalmeh and L. WeiAn integrated study has been carried out to understand the field performance and remaining oil distribution
of a heterogeneous and oil-wet carbonate reservoir under waterflood. The reservoir under study is a
layered system where strata measuring a few feet in thickness can be correlated field-wide. The reservoir
consists of two main units, i.e. a Lower zone of generally low permeability layers and an Upper zone of
high permeability layers inter-bedded with low permeability layers; the average permeability of the Upper
zone is some 10-100 times higher than that of the Lower zone.
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Optimal Design Criteria for SAG Foam Processes in Heterogeneous Reservoirs
Authors M. B. Kloet, W. J. Renkema and W. R. RossenFoam can increase sweep efficiency in gas-injection IOR processes. Here we develop design criteria for
surfactant-alternating-gas foam processes in layered reservoirs. We reach the following conclusions:
Trends of foam strength with permeability or surfactant formulation, as measured in conventional
coreflood tests at fixed injected water fraction, may not correspond to behavior in a SAG process in the
field. In the cases examined, foam strength in a SAG process is much less sensitive to permeability and
foam parameters than is foam strength at fixed injected water fraction.
Placement of surfactant into low-permeability layers is a key challenge of SAG processes in
heterogeneous reservoirs. Gas breakthrough occurs via low-permeability layers that did not receive enough
surfactant. For that reason, a stronger foam that more effectively diverts flow away from higherpermeability
layers may send more gas to lower-permeability layers that lack surfactant, and thereby
accelerate gas breakthrough.
Using multiple surfactant and gas slugs allows foam to redistribute surfactant in later slugs.
However, this strategy suffers from poor injectivity during liquid injection, which slows the process and
promotes gravity segregation.
Injection of both gas and surfactant slugs at the maximum allowed injection pressure, rather than
at fixed rate, gives best results.
Injecting gas from only the bottom of the well offers no significant advantages in the best case,
where a high-permeability layers lie at top and bottom of the reservoir, and performs significantly worse if
low-permeability layers lie at the top (where lack of surfactant leads to override) and bottom (where low
permeability restricts injectivity) of the reservoir.
A surfactant slug sized for a homogeneous reservoir is too large for a heterogeneous reservoir,
because little surfactant enters lower-permeability layers: much of the injected surfactant goes to waste. A
surfactant slug sized to sweep high-permeability layers and a portion of low-permeability layers performs
nearly as well as one sized to sweep the entire reservoir.
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Gravity Segregation in Gas IOR in Heterogeneous Reservoirs
Authors W. R. Rossen and G. H. StolwijkVertical segregation of gas to a thin override zone is a major limitation on sweep efficiency and oil
recovery in gas improved oil recovery (IOR), including CO2 sequestration in oil reservoirs. Stone (SPE
11130, 1982) and Jenkins (SPE 12632, 1984) present an elegant and powerful model for gravity
segregation for co-injection of gas and liquid in homogeneous reservoirs. They contend that the model
applies also to WAG. In this study we extend the model of Stone and Jenkins to heterogeneous (layered or
checkerboard) reservoirs, as representatives of reservoirs with long- or short-range lateral autocorrelation
of permeability, and test the extension with simulation.
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Experimental and Numerical Modeling Studies of Viscous Unstable Displacement
Authors A. Skauge, K. Sorbie, P. A. Ormehaug and T. SkaugeExperimental studies of fluid flow at adverse mobility ratio have quantified the development of viscous
fingers. CIPR have developed an experimental set up for 2-D in-situ saturation measurements. The X-ray
scanner can quantify saturations over a large 2-D area and can also image saturation changes of up to 1 x 1
m rock slabs. The 2-D scanner is designed specifically to study viscous unstable displacements for both
miscible and immiscible processes.
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Experimental Investigation of Effect of Depletion Rates on Recovery of a Heavy Oil Reservoir
Authors S. A. Mirhaj, M. Fazaelizadeh, P. L. J. Zitha and R. KharratHeavy-oil reservoirs in western Canada and Venezuela show high primary recovery under solution gas
drive mechanism. Pressure decline rate in these reservoirs is low compared to that expected under solution
gas drive in conventional oil reservoirs due to high viscosity. Several studies have been reported a
dramatic effect of depletion rate on performance of solution gas drive in heavy oil system.
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Selection of a New IOR/EOR Strategy for the Heavy Oil Brown Field in Kazakhstan
Authors A. A. Mosesyan, S. A. Nagorniy, E. A. Chernitsyna and Y. A. TrotsenkoThe World experience proved that heavy oil fileds potential is highly dependent on the proper IOR/EOR
strategy assigned for the field from the first days of development. This crucial goal becomes additionally
complicated when you're handling brown field and are limited in choice of methods.
So, the development of IOR/EOR strategy for a heavy oil brown field becomes a serious challenge,
especially if the current status of the field development demonstrates the ineffectiveness of the initially
applied production methods.
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Miscible Carbon Dioxide Flood Imaging – Analysis of 4D Seismic Wavelet Transform Spectral Composites
Authors A. E. Raef, L. W. Watney and A. P. ByrnesSubtlety of 4D seismic anomalies, in carbonates, call upon using high-resolution seismic, which require
very demanding tighter cross-equalization standards. We present a non-equalization approach utilizing
wavelet transform (WT) spectral components of time-frequency-amplitude analysis of 4D seismic data for
both, imaging EOR/sequestration Carbon Dioxide flood in a thin (3-5 m thick) Upper Pennsylvanian
oomoldic carbonate reservoir in central Kansas-USA, and for helping to identify fluid-flow controls.
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Direct Observation of CO2 Transport and Oil Displacement Mechanisms in CO2/Water/Oil Systems
Authors M. Riazi, M. Riazi, M. Jamiolahmady, S. Ireland and C. BrownAs the concern over the greenhouse gas effects of carbon dioxide (CO2) increases, its injection into oil and
gas reservoirs for enhancing hydrocarbon recovery and in saline aquifers for storage is on the rise.
Variation of reservoir pressure and temperature affects the properties of CO2 and its interaction with
reservoirs resident phases. Although in most cases CO2 would be in supercritical state at reservoir
conditions, however, it is necessary to understand the flow and displacement mechanisms of CO2/water/
oil systems in porous media under various reservoir conditions.
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Modelling of CO2 Injection
Authors L. Surguchev and G. CalderonThis paper presents results of secondary CO2 and CO2-rich gas injection experiments and simulations.
Displacements were performed in Berea cores under viscous dominated flow regime in order to evaluate
viscous effects at CO2 injection. The formation of three hydrocarbon phases under CO2 flood and its
effect on oil recovery have been already investigated in some core flood experiments. Few experimental
evaluations of CO2-rich phase injection effects have been performed at high pressure and above CO2
critical temperature. Immiscible CO2 injection was performed in high and low viscosity oil saturated
cores. Later gas breakthrough and higher oil production were observed at lower oil viscosity experiments.
The ultimate oil recoveries for low and high viscosity oils were very close at continuous CO2 injection. In
the floods with CO2-rich phase the achieved oil recovery could be correlated with CO2-rich phase
volume. Total oil recovery increases as the CO2-rich phase volume increases and miscible displacement
develops. Due to oil vaporisation and stripping by the moving CO2 tail-front significant amounts of oil
can be produced after the breakthrough of CO2. Representative simulation of CO2 injection requires
accurate modelling of viscous effects and formation of CO2-rich phase.
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Three–Phase Flash in Compositional Simulation Using a Reduced Method
Authors R. Okuno, R. T. Johns and K. SepehrnooriCO2 flooding at low temperatures often results in three or more hydrocarbon-phases. Multiphase
compositional simulation must accurately simulate such gas floods. Drawbacks of modeling three
hydrocarbon-phases are the increased computational time and convergence problems associated with flash
calculations. Use of a reduced method is a potential solution.
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Fractional-Flow Theory of CO2 Foam Displacements with Surfactant Dissolved in the CO2
Authors E. Ashoori, T. L. M. van der Heijden and W. R. RossenA foam process with surfactant dissolved in supercritical CO2 has the advantage that injection of CO2,
once begun, need never be interrupted for surfactant injection in water. In addition, CO2 can carry
surfactant to layers that may not be swept by an aqueous surfactant slug. CO2 carries the surfactant and
forms foam with water in the formation.
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Asphaltene Deposition during CO2 Injection in an Iranian Carbonate Reservoir – An Experimental and Simulation Approach
Authors S. H. Mirhaj and S. A. MirhajIn a CO2 miscible displacement process, the injected CO2 solvent can induce flocculation and deposition
of asphaltenes and other heavy organic particles. This can cause numerous production problems with a
detrimental effect on oil recovery. Therefore, it is important to understand the behavior of this organic
matter under reservoir operating conditions.
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A New CO2 EOR Predictive Correlation
Authors J. Brodie, B. Jhaveri and D. PuckettMiscible CO2 flooding is a well-established method for enhancing oil recovery and is the subject of
renewed interest as an option to control emissions of greenhouse gases. There is a requirement for rapid
screening of reservoirs for CO2 flooding prior to undertaking detailed, resource-intensive studies. In this
paper, we describe a new CO2 EOR predictive correlation that has been developed to screen tertiary CO2
floods in sandstone reservoirs. The new correlation was developed by fitting a response surface model to
a large simulation database. The simulation data were generated by varying key reservoir and fluid
properties in a fully compositional finite difference model. The new correlation has been validated against
additional simulation cases and historic CO2 floods in sandstone reservoirs and can be applied to cases
where existing models (e.g. Claridge, 1972) give inaccurate results. The new correlation is recommended
for high-level screening of CO2 EOR.
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Simulation Aspects of the CO2 EOR Including Foam
Authors R. A. Berenblyum, J. F. Zuta, I. Fjelde and L. M. SurguchevThis paper addresses simulation aspects of the CO2 injection into the porous media. The presented results
are based on the mechanistic and laboratory scale simulations. These findings would lay out the basis for
the field scale CO2 injection pilot.
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CO2-Foam Processes in a Fractured Chalk Model
More LessThe injection of CO2 with a suitable aqueous solution of a CO2-foaming agent into a reservoir formation
has been shown to improve on CO2 mobility and increase macroscopic sweep efficiency. However, during
CO2-foam flooding in fractured chalk reservoirs with low matrix permeability compared to fracture
permeability, the solutions will mainly be transported through the fracture network. At higher matrix
permeability, viscous flooding of the matrix will also be important. Foam in fractures can divert more of
the CO2 and surfactant solution to the matrix.
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Correlation between SAGD Steam Chamber Growth and Geological Heterogeneity
Authors I. D. Gates and D. GotawalaEvolution of Steam Assisted Gravity Drainage (SAGD) steam chambers in heavy oil and bitumen
reservoirs is tied to: 1. uniformity of steam pressure and quality along the length of the perforated interval
of the well and 2. reservoir geology and fluid properties adjacent to the well. If steam delivery into the
injection well is not uniform, then non-uniform steam is delivered to the reservoir along the wellpair. If
the reservoir geology has poor permeability at an interval along the wellpair, then steam delivery to and
fluids production from the reservoir is not uniform. If the steam is well distributed throughout the
injection well, then the key factor for a uniform steam chamber along the wellpair is reservoir geology.
This is especially important in highly heterogeneous, variable thickness reservoirs where geology and
reservoir oil composition may vary significantly over the length of a wellpair. In this study, heterogeneity
of a growing SAGD steam chamber is related to heterogeneity of the underlying geology. Here, the oil
sand models are geostatistically populated to model heterogeneity of porosity and permeability.
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Regularities of Alternated Displacement of High-Viscosity Oil by Steam and Surfactant-Based Systems, Generating CO2 in s
Authors L. K. Altunina, V. A. Kuvshinov and I. V. KuvshinovA complex EOR technology has been developed at the Institute of Petroleum Chemistry SB RAS to
increase the efficiency of thermal-steam and cyclic-steam treatments of high-viscosity oil pools by
surfactant-based systems capable to generate СО2 and alkaline buffer solutions in situ. Presented are the
results of laboratory research on the effect of the concentration of oil displacing systems and slug volumes
on oil displacement factor under the conditions simulating thermal-steam and cyclic-steam treatments. It
has been determined that alternation of steam slugs and oil displacing system allows one to obtain higher
values of oil displacement factor as compared to thermal-steam treatment. The injection of the first system
slug provides the major contribution to the increase in oil displacement factor. Generalizing dependencies
of oil displacement factor on the accumulated volume of the system injection were deduced. Under field
conditions it is recommended to use surfactant-based systems at concentration of 50 %. Computer
programs were developed to calculate the volumes of oil displacing systems at planning pilot tests. In
2002-2008 pilot tests of the complex technology were carried out in oil fields of Russia and China to
enhance oil recovery from high-viscosity oil pools. The results of the tests are presented.
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4D Seismic Modelling Applied to SAGD Process Monitoring
Authors O. Lerat, F. Adjemian, A. Auvinet, A. Baroni, E. Bemer, R. Eschard, G. Etienne, G. Renard, G. Servant, S. Rodriguez, E. Bathellier and E. ForguesThe performance of heavy-oil production by Steam-Assisted Gravity Drainage process (SAGD) can be
affected by near-well reservoir heterogeneities. However, as many factors interact during thermal
production such as changes in oil viscosity, fluid saturations, pore pressure, stresses,... the interpretation of
4D seismic data in terms of steam chamber geometry is not direct nor unique.
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Optimization of Solvent – Based Enhancements of Steam Assisted Gravity Drainage
Authors T. Ibatullin and A. B. ZolotukhinModern Steam Assisted Gravity Drainage (SAGD) technology has proven its efficiency throughout the
world. However, sometimes steam generation by natural gas combustion can render the process
uneconomic. Moreover, ever-increasing environmental concerns and green house gases emission s
restrictions require further improvement of the existing technology. In addition to overcoming
environmental issues, operators are also interested in improving SAGD s performance in terms of daily
rates and recovery factors.
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Experimental and Numerical Analysis of In Situ Combustion in Fractured Carbonates
Authors H. Fadaei, A. Kamp, G. Debenest, L. Castanier and M. QuintardApproximately one third of global heavy oil resources can be found in fractured reservoirs. In spite of its
strategic importance, recovery of heavy crudes from fractured reservoirs has found few applications due to
the complexity of such reservoirs. In situ combustion is a candidate process for such reservoirs, and
especially for those where steam injection is not feasible. Experimental studies reported in the literature on
this topic mentioned a cone-shape combustion front, indicating that the process was governed by diffusion
of oxygen into the matrix. The main oil production mechanisms were found to be thermal expansion of oil
and evaporation of light components.
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Automated History Matching of Combustion Experiments Using the Ensemble Kalman Filter
In-situ combustion (ISC) and High Pressure Air Injection (HPAI) are enhanced oil recovery processes, in
which air or oxygen enriched air is injected into a reservoir. The oxygen present in the air reacts with the
crude oil in the reservoir. This results in a combustion front propagating through the reservoir, generating
heat and flue gases. Many chemical reactions take place over different zones and temperature ranges
during the process. Reaction schemes based on pseudo components are used in numerical simulations to
describe these reaction processes. The kinetics of these reactions are given by Arrhenius-type equations.
A still remaining challenge in combustion modelling is the estimation of the Arrhenius kinetic parameters.
Combustion tube experiments are therefore performed to obtain information about the burn characteristics
that depend on the crude and reservoir rock properties. The Arrhenius parameters can be estimated by
history matching these experiments. The obtained values have to be up-scaled before they can be used for
field-scale simulations. History matching the combustion tube experiments is an intensive and timeconsuming
process, because multiple reactions occur at the same time and because non-unique matches
are expected. An automated history-matching tool for combustion tube tests is desired to quantify
uncertainty in the obtained kinetic parameters and reduce time spend to obtain a good match. In this work
a method is described for the automated history matching of combustion tube experiments using the
Ensemble Kalman Filter (EnKF).
The Ensemble Kalman Filter is a sequential data assimilation technique that combines measurement series
with dynamic models. The EnKF uses a Monte Carlo approach in which model errors are represented by
an ensemble of realizations. The ensemble is integrated in time to make predictions on system parameters
and state variables and their uncertainties.
The method to history match combustion tube experiments using the Ensemble Kalman Filter is described
in this paper and applied to combustion tube experiments. The matching of the combustion tube test is
based on temperature profiles, oil and water production data and effluent composition. It is shown how the
initial uncertainty in the kinetic parameter ranges (activation energy and frequency factor) are reduced by
automated history matching of the experiments, using the EnKF method.
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Analytical Study of In-situ Combustion in a Wet Porous Medium
Authors G. Chapiro, A. A. Mailybaev, H. Bruining and D. MarchesinThere is a renewed interest in using combustion for the recovery of medium viscosity oil. In-situ
combustion is commonly divided into zones according to the main processes occurring inside.
In the downstream order they are combustion, coke, cracking, steam and light hydro-carbon zones. In this
analytical study the cracking reaction and the light hydro-carbon vaporization process are neglected for
simplicity. We take into account the reaction occurring between the residual petroleum coke and the
oxygen contained in the injected air. We also assume the presence of small amount of immobile liquid
phase, which can vaporize; this feature is useful if this study is applied to gasefication of coal
containing water.
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“Smart Water” as Wettability Modifier in Carbonate and Sandstone
Authors S. Strand, A. R. Doust, T. P. Puntervold and T. A. AustadWaterflooding has for a long time been regarded as a secondary oil recovery method. In the recent years,
extensive research on crude oil, brine, rock (COBR) systems has documented that the composition of the
injected water can change wetting properties of the reservoir during a waterflood in a favorable way to
improve oil recovery. Thus, injection of Smart Water with a correct composition and salinity can act as a
tertiary recovery method. Economically, it is, however, important to perform a water flood at an optimum
condition in a secondary process. Examples of Smart Water injection in carbonates and sandstones are:
Injection of seawater into high temperature chalk reservoirs
Low Salinity floods in sandstone reservoirs
The chemical mechanism behind the wettability alteration promoted by the injected water has been a topic
for discussion both in carbonates and especially in sandstones. In this paper, the suggested mechanisms for
the wettability modification in the two types of reservoir rocks are shortly reviewed with a special focus on
possible chemical similarities. The different chemical bonding mechanisms of polar components from the
crude oil onto the positively charged carbonate and the negatively charged quartz/clay indicates a different
chemical mechanism for wettability modification by Smart Water in the two cases.
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Sweep Improvement from the Lab to the Field
Authors H. Frampton, P. Denyer, D. H. Ohms, M. Husband and J. L. MustoniIn the early 1990 s BP pioneered the use of reservoir triggers for in-depth placement of chemical
treatments to improve water flood sweep efficiency. It was recognised that the most difficult cases
involved injection water thief zones that were in contact with lower permeability zones of high remaining
oil saturation. In such cases near well-bore treatments were ineffective and an in- depth block appeared to
be required to redistribute the pressures in the reservoir and mobilise the remaining oil. The lessons
learned from this work suggested that the most effective treatments would employ single component
materials placed deep in the formation. A particulate material was envisaged that was likened to popcorn.
It would move freely through the matrix rock until a reservoir trigger caused the particles to increase in
size to block thief zone pore throats.
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Cross-well Electromagnetics – Enhancing Reservoir Management
Authors A. V. Nalonnil, L. Reynolds, P. Zhang and M. WiltSecondary recovery methods such as water flooding and derivatives of this such as water alternating gas
(WAG) are paramount to enhancing production. Managing and optimizing these injections before break
through and locating by-passed hydrocarbons in un-swept zones can help recover significant amounts of
hydrocarbon.
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Restriction of Water Production in Gas Wells Using Water Sensitive Microemulsions
Authors I. J. Lakatos, J. Lakatos-Szabó, T. Bódi and Á. VágóAs a novelty, water sensitive water external microemulsions were developed, which are stable until they
are diluted with water. Transformation of different metastable systems to stable macroemulsions in
reservoir space having high water saturation may radically restrict the water flow and that is attributed to
their high viscosity and entrapment of the dispersed particles by the pores. As dispersed phases, organic
silicon compounds, ten-sides and natural crude oil fractions were tested. The transformation and structure
of phases and size of particles were analyzed by photon correlation spectrometry, rheometry, while the
flow properties were studied in natural sandstone systems.
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Performances in Harsh Environments of Water Shutoff and Conformance Control Microgels
Authors D. Rousseau, C. Cozic and R. TabaryMicrogels are polymeric chemicals specifically designed for enhanced water shutoff and conformance/
profile control applications. Microgels are micron-size particles which are preformed, stable, fully water
soluble and size-controlled with a narrow distribution. Being non toxic, according to the OSPAR
environmental tests, and available under powder form, they are also particularly well suited for offshore
operations. Their long-term stability was checked at temperatures up to 165°C (329°F). In porous media,
microgels allow a controlled permeability reduction to water through a monolayer adsorption. When
injected in a heterogeneous reservoir, unlike conventional polymer-based systems, microgels invade
significantly less the low permeability layers than the high permeability ones, thanks to their low viscosity
in solution as well as to steric effects.
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Static and Dynamic Adsorption of Salt Tolerant Polymers
Authors M. Rashidi, S. Sandvik, A. M. Blokhus and A. SkaugeA key parameter for application of polymers for waterflood mobility control is the loss of polymer due to
adsorption to the rock and more general retention during flow in porous medium. The paper discusses the
adsorption and retention properties of sulfonated co-polymers. These polymers have the same backbone
structure as partly hydrolysed polyacrylamide (HPAM), except for modified hydrophobic groups and that
the polymer is sulfonated to some extent. The group of polymers has been studied because of unusual salt
tolerance compared to other synthetic polymers. There is a need for polymers for high temperature and
high salinity reservoirs.
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Injectivity of Hydrophobically Associative Polyacrylamides for IOR: Impact of the Chemical Composition
Authors G. Dupuis, D. Rousseau, R. Tabary and B. GrasslInjectivity of associative polymers is a key parameter to control when considering their application in both
mobility control and well treatment operations. This work reports on the impact of chemical composition
of hydrophobically modified sulfonated polyacrylamides (HMSPAM) on their injectivity. The parameters
investigated are the molar fraction of hydrophobic comonomers and the size of the alkyl chains. A wide
range of HMSPAM and equivalent non-associative sulfonated polyacrylamides (SPAM) has been
synthesized using micellar radical polymerization. The copolymers have been extensively characterized
using NMR spectroscopy and size exclusion chromatography. Then, solution properties of the polymers
have been studied in terms of rheology and size determination by dynamic light scattering, prior to
injecting them in membranes with calibrated capillary pores.
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Investigating the Effect of Co-Solvents on Heavy Oil Recovery in Different Pore Geometries Using Five-Spot Micromodels
Authors S. Vossoughi, A. A. Dehghan, R. Kharrat and M. H. GhazanfariThe main issue in heavy oils enhanced recovery methods is to reduce their viscosity in order to get a
better mobility. This is commonly obtained by blending the oil with light hydrocarbons. Co-solvents are
good candidates to improve the hydrocarbon recovery efficiency especially in miscible processes.
However, the effect of co-solvents on miscible flooding of heavy oil reservoirs at different pore geometries
is not well understood.
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Change to Low Salinity Brine Injection in Combination with Surfactant Flooding
More LessIt is known that surfactant flooding can be efficient when using a salinity gradient. A gradual reduction in
salinity with time controls the surfactant phase behaviour, and ensures minimum interfacial tension (IFT)
to be achieved within the salinity gradient. The surfactant ends up as oil in water microemulsion in the low
salinity water chasing the surfactant slug.
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Improved Reservoir Characterization and IOR Program to Extend the Life Cycle the Mature Field
Authors V. Terentiev, I. Nagornaya, I. Kharitonov, V. Bek-Nazarov and E. PolyakovA decision on field re-development scenario is usually based on extensive volume of seismic, logs and
core data. In our paper we study the case of a mature field in the Volga river basin, where the amount of
available geological information was limited.
The Vorobiev horizon of Devonien formation at this field in Saratov region is in production since 1954.
During the 1992-2001 period ten new production wells were drilled. New well data allowed to improve
reservoir characterization, update structural maps, establish new geological models and revise the
remaining oil reserves. The new models helped to locate the remaining oil reserves in the structural flanks.
The re-development program with drilling of infill and side track horizontal lateral wells together with
well stimulation methods is proposed. If the proposed measures are implemented, the oil recovery at this
field could be increased by 10-11% to achieve more than 77% of STOOIP.
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Implementation of IOR - EOR Projects in ONGC; An Overview
By R. K. PatiImproved Oil recovery and Enhanced Oil Recovery projects form one of the strong pillars of success for
improving performance of the Upstream Petroleum Companies.
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Feasibility Study of Gas-Based EOR Processes in a North Sea Oil Reservoir
Authors D. G. Hatzignatiou and P. PermataThis work investigates the potential standalone field re-development of a small North Sea oil field through
the deployment of a gas injection process that utilizes the produced gas as the key enhanced oil recovery
(EOR) agent. A field-sector, compositional simulation model is constructed to evaluate and compare the
most promising gas-based EOR techniques such as continuous gas injection, water alternating gas and
simultaneous water and gas injection processes against water injection. Sensitivity studies are conducted to
optimize the conditions/parameters of the selected EOR technique and practical issues that can influence
oil recovery factors are evaluated for a potential pilot or field-wide scale implementation.
The results indicate that the implementation of a Simultaneous Water And Gas (SWAG) EOR injection
process that makes use of the field produced gas and having undergone a thorough and field-wide
optimization of operational parameters (produced gas availability, fluids injection rate, injection water-gas
ratio, production and injection wells BHP, fluids injection scheme, etc.) as well as a careful investigation
of potential well interventions to increase oil production (selective re-perforation of existing wells,
possible shutoff of excess water, etc.) could be a viable EOR technique for re-developing this asset.
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Incremental Oil Success from Waterflood Sweep Improvement in Alaska
Authors D. H. Ohms Inc., J. D. McLeod, C. J. Graff, H. Frampton, K. T. Chang, J. C. Morgan, S. Cheung and K. YanceyWaterflood thief zones in communication with the rest of the reservoir are a severe and previously
challenging problem. This poster gives an introduction to the nature of a novel heat-activated polymer
particulate. Details of a trial of this in-depth diversion system, resulting in commercially significant
incremental oil from a BP Alaskan field are presented. The treatment was designed using laboratory tests
with slim tube sand packs, and numerical simulation informed by pressure and chemical tracer tests.
Placement deep in the reservoir between injector and producer, was confirmed by pressure fall off analysis
and injectivity tests. The incremental oil predicted from the simulation was 7949 to 39747 m3 (50,000 to
250,000 bbl) over 10 years. In fact over 9639 m3 (60,000 barrels) of oil was recovered in the first 4 years.
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Investigating the Effect of Solvent to Oil Volume Ratio on Asphaltene Deposition
Authors M. Amani and A. HaghshenasUnderstanding the nature of heavy organic compounds and the mechanisms of their depositions is
essential with the increased utilization of deeper reservoirs (heavier asphaltic crude) and miscible flooding
techniques for recovery of oil. To prevent asphaltene deposition in different places, it is necessary to
predict the onset and the amount of deposition due to various factors.
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Sensitivity Analysis to Investigate Possibility of Steam Injection in an Iranian Carbonate Heavy Oil Field
Authors M. Amani and A. HaghshenasSteam injection in naturally fractured heavy oil reservoirs provides an extremely challenging problem as
well as a potentially effective and efficient improved oil recovery method. Coupling of the two distinct and
contrasting matrix and fracture systems results in a highly non-linear problem, and it gets even more
complicated as a result of steep changes in fluid properties due to the thermal effects of steam injection.
Modeling and designing an optimum steam injection operation in such systems requires an accurate
characterization and representation of a naturally fractured heavy oil reservoir and steam injection
operation parameters and dynamics.
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Experimental Investigation of Hot Water Injection into Low-permeability Carbonates Heavy Oil Reservoirs
Authors B. Sedaee Sola, F. Rashidi and L. Hamidi SolaThe major mechanisms on hot water injection are: thermal expansion, viscosity reduction, wettability
alteration and oil / water IFT reduction. In this study, hot water injection experiments were carried out
using unpreserved carbonate core samples obtained from the oil zones of heavy oil low- permeability
reservoirs. These experiments were conducted at reservoir condition and in various temperature ranges up
to 500°F using wide variety of oils. The final oil recovery, residual oil saturation, irreducible water
saturation and pressure drop were compared in each experiment. Results show that it is possible to recover
high percent of oil using high pressure/temperature injection even from heavy oils in low-permeability
carbonate reservoirs. In the heavy oil system, the oil production to hot water injection ratio is higher than
the medium and the extra heavy oil, but the values are less than the reported values for conventional heavy
oil reservoirs. Also it was found that the residual oil saturation decreases and irreducible water saturation
increases when the temperature increases.
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Investigation of Fractures Geometrical Properties on Conventional Fire Flooding (CFF) Process Performance
Authors C. Ghotbi, S. M. Fatemi and R. KharratThe Conventional Fire Flooding (CFF) has been studied deeply in conventional reservoirs as a promising
EOR method for certain non-fractured sandstones; however, its application feasibility in fractured
carbonates remained questionable. The aim of the present work was to evaluate the effect of fractures
geometrical properties such as orientation, density, location and networking on the CFF process
performance. Combustion parameters of a fractured low permeable carbonate heavy oil reservoir in Iran
called Kuh-E-Mond; applied to simulation study. Simulator has been validated with KEM combustion tube
experimental data. Validated model modified to study CFF in a 3D semi-scaled combustion cells. Oil
recovery was slower in the case of fractured models compare to the conventional one since in the former
the governing mechanism is oxygen diffusion from matrix into fissure and vice versa which will be
prolonged. This prevailing mechanism reduced rate of oil recovery in the presence of either traversal or
longitudinal fractures. Ultimate oil recovery was higher in the case of near injector traversal fissures
compare to near producer ones. CFF performance was lower in the case of near injector longitudinal
fractures compare to the farther ones. Contrary far injector longitudinal fissures improved the areal sweep
efficiency of oxygen at the lateral side of the combustion cell and hinder the cone liked shape of air profile
in conventional model. Higher traversal fracture density reduced oil recovery due to consequent matrixfractures
diffusion compare to improved recovery performance in the case of higher traversal fracture
density. In the case of networked fractures longitudinal fissures enhanced the performance of traversal
fractures and higher ultimate oil recovery compare to the case of either traversal or longitudinal fissures
obtained which confirmed that CFF is more feasible in the case of densely fractured reservoirs such as
those in the Middle East.
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Optimal Well Placement for Heavy Oil and Bitumen Reservoirs with Vertical and Lateral Oil Mobility Distributions
Authors I. D. Gates, S. R. Larter and J. J. AdamsDarcy s law shows that the primary control on gravity-driven bitumen speed within oil sands reservoirs is
oil mobility, the quotient of oil effective permeability and viscosity. The controlling factors on oil
effective permeability are absolute permeability and oil relative permeability which in turn depends on oil
saturation. The controlling factors on oil viscosity are temperature and composition which in turn is set by
the amount of solution gas, reservoir geology, charge rate, biodegradation and diffusion of light end
components, availability of water for biodegradation, and temperature history. The absolute permeability,
rock type (relative permeability), fluid saturations, and compositions are all heterogeneous in oil sands
reservoirs with differing variability in vertical and lateral directions. Current thermal recovery processes
such as SAGD use straight wells that are convenient for drilling and planning but are not optimized with
respect to oil mobility distribution. This research examines what the optimum SAGD wellpair trajectory
would be in a fully heterogeneous reservoir. The research not only reveals that the optimal well trajectory
may not be straight but that injectors and producers need not be parallel to each other.
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Summary of Nitrogen Miscibility with Oil For Gas Displacement Recovery
Authors M. H. Holtz and N. CornaWith today s Socioeconomic climate, reserve growth from already discovered fields is again a key industry
focus. An important approach to enhanced oil recovery (EOR) reserve growth is gas displacement
recovery (GDR) with nitrogen. N2 GDR projects around the world today are currently injecting over 1.8
billion standard cubic feet per day (BSCF/d). The methods applied have included: immiscible
displacement, pressure maintenance in oil reservoir gas caps and condensate gas reservoirs, gravity
drainage, N2 as a driving agent for a cushion gas, and miscible displacement.
The implementation of a miscible displacement project depends on engineering with the N2 - oil
Minimum Miscible displacement Pressure (MMP) property. In this study we review and summarize the
state of knowledge for determining N2 - oil MMP. Past published laboratory work has been summarized
and compared. This includes the influences on MMP and the variability in estimation. For simulation
equation of state (EOS) approaches have also been summarized, variably described, and best practices
noted.
Laboratory measured MMP data displays considerable variability and is affected by oil composition and
reservoir conditions. This paper summarizes the state of our current N2 miscibility knowledge, exploring
the effects of fluid and reservoir conditions.
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Combining Proven Technologies into a Profitable Steamflood
Authors F. Jelgersma, Martinde Keijzer, JanWillem Flamma and Basvan HaarlemThe onshore Schoonebeek oilfield produced 25% of its 164 million m³ STOIIP from 1943 until 1996,
when exploitation was stopped, wells were abandoned and the surface infrastructure was removed. A 2003
study showed that the part of the field where the main drive mechanism was Solution Gas Drive is suitable
for redevelopment. The recovery factor in this area is 15%, which includes some recovery from water
injection and small-scale thermal EOR projects. Through 1960-1975 a successful small low-pressure
steam flood project with vertical wells was done in this area. Based on this success and the proven
suitability of horizontal wells in steam floods, a redevelopment was proposed using horizontal wells in a
low-pressure steam flood. However, the green-field state of the abandoned field made the threshold for
the investment decision high. Selection of proven technologies and rigorous handling of uncertainties led
to approval of the project and acceptance by the majority of third party stakeholders. Full field thermal
dynamic reservoir modeling was used to determine the optimal well placement. Full analysis of the project
sensitivity to subsurface uncertainties provided confidence in the predicted production performance. Use
of horizontal wells reduces the number wells and surface locations. Acquisition of high-resolution seismic
reduced structural uncertainty and detailed 3D static modeling helped well planning. Proven thermal well
completion technologies will be used, such as Limited Entry Perforations (LEPs) to ensure uniform steam
distribution in steam injectors. ROTAFLEX' long stroke rod pumps will be used to ensure that highly
productive wells produce at the required rates at high temperatures. A Combined Heat and Power plant
will generate steam and electricity efficiently, reducing the CO2 footprint. After treatment, oil will be
exported to a third party refinery in Lingen (Germany) and produced water will be injected into depleted
gas fields in the region. The 73 development wells will be campaign drilled beginning early 2009 using a
specially built rig.
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Investigation of Field Scale Dispersion
Authors A. K. John, L. W. Lake, S. L. Bryant and J. W. JenningsSummary not available
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Improved Oil Recovery from Tensleep Sandstone – Studies of Brine-Rock Interactions by Micro-CT and AFM
Authors E. Lebedeva, T. J. Senden, M. Knackstedt and N. MorrowNumerous laboratory studies show that oil recovery by waterflooding can depend on the composition of
the injected water. In particular, low salinity water injection has been shown to improve oil recovery in
both laboratory core floods and field pilot tests. While the presence of clay, crude oil, and an initial water
saturation have all been identified as minimal and necessary conditions for increased recovery from clastic
rocks, their relationship as well as other relevant conditions remain uncertain.
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Single-Well Chemical Tracer Tests (SWTT) experience in the Mature Handil Field: Evaluating Stakes before launching an EOR Project.
Authors C. Romero, F. Aubertin, E. Cassou, P. Cheneviere, J. S. Tang, J. Odiorne, P. Cordier and J. BatiasThe success of EOR projects in targeting residual reserves in mature fields strongly depends on having an adequate description of both remaining oil distribution (ROS) and reservoir heterogeneity to correctly locate EOR objectives. As a consequence, many projects are incorporating the use of tracers to better characterize candidate fields and to identify, among others, remaining oil and the existence of preferential flow paths or flow barriers that could affect EOR recovery.
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