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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
41 - 60 of 64 results
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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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