bluuebunny/crossref_metadata_2025_split huggingface dataset:
Adsorption of EOR Chemicals Under Laboratory and Reservoir Conditions, Part II: Bacterial Reduction Methods
Authors: Harris H. Wayne , Grimaud Regis , Levitt David 
Published: August 2015

AbstractWe have successfully performed bacterial reduction of an iron-containing outcrop sand sample under static conditions using Shewanella genus bacteria. Adsorption of an anionic (alkyl benzyl sulfonate) surfactant was around 7-times lower on treated outcrop samples. Most of this reduction (~3X) occurs over the first 3-4 days of incubation, contemporaneously with iron dissolution and limited biofilm formation. Continued incubation after this point attends the formation of significant biofilm, as well as a continued decrease in surfactant adsorption. Non-iron-reducing bacteria also formed biofilm on outcrop samples, yielding a significant (though smaller) decrease in surfactant adsorption. Microscopy demonstrates preferential attachment of biofilm to iron minerals in a heterogenous outrop sample. Repeated rinsing results in a removal of biofilm formed by iron-reducing or bacteria and a corresponding increase in surfactant adsorption to about 1/3 to 1/2 of original levels.This proof of concept for a bacterial core restoration method using iron-reducing bacteria is considered successful, with the caveat that care must be taken to minimize and/or remove biofilm in order to avoid biofilm-related artifacts. Implications of these results for the determination of reservoir rock-fluid properties in biologically-active reservoirs are also discussed.
Well, Reservoir and Facilities Management (WRFM) and Surveillance Planning in a Multi-Stacked Mature Oil and Gas Field in Baram Delta
Authors: Cakici Mahmut Deniz , Diomampo Gracel , Diri Muhammad , Hashim Suraini , Sdn Berhad Sarawak Shell , Wibowo Suryadi 
Published: August 2015

Abstract
The oil field is located 40 km offshore Sarawak, Malaysia in the southwestern part of the Baram Delta at a water depth of 250 feet. It is an anticline bounded by two (2) sealing faults and composed of multiple hydrocarbon bearing sand reservoirs separated by sealing shale layers. Oil has been produced since 1972 from more than 10 different reservoir units.
Enhanced oil recovery (EOR) redevelopment project in the field will begin in 2018. The project will increase the crestal gas injection and initiate water injection at various locations in the water leg for two (2) major oil rim reservoirs. In a third relatively smaller reservoir water and immiscible gas will be injected in an immiscible Water-Alternating-Gas (iWAG) scheme. Required gas for the entire project will be supplied from five gas reservoirs, as well as by recycling the produced gas from the oil reservoirs. A Well, Reservoir and Facilities Management, or WRFM, plan was put together to prepare the reservoirs for the EOR project and to further optimise the development decisions.
This paper outlines the objectives of the WRFM plan for the EOR redevelopment project. Key uncertainties that have an impact on the development plans are highlighted. A summary of surveillance activities required to manage the key uncertainties are given.
At the end, focusing on the XE/XF reservoir group, reservoir surveillance required to monitor and manage a mature off-shore oil rim reservoir is discussed. XE/XF reservoir has a large gas cap and surrounded by an aquifer. The oil rim is dynamic in nature, which moved into the gas cap after the start of production due to the imbalance between the strong aquifer and gas cap expansion. For pressure maintenance purposes, as well as to prevent the rise of the oil rim, gas injection into the cap was started in 2001. Most recent saturation logs show that the current oil-water and gas-oil contacts in the field can no longer be regarded as even surfaces. The surveillance plan focuses on monitoring the saturation and pressure changes in the reservoir to locate the current gas-oil and oil-water contacts, and to understand the strength of the surrounding aquifer. The learnings will impact the number and locations of production and injection wells that are planned to be drilled as a part of the EOR project. In addition, the results will be used to update the existing dynamic reservoir model, which will be utilised for long term reservoir management.
Mechanistic Modelling of Alkaline/Surfactant/ Polymer Flooding Process at Under-Optimum Salinity Condition for Enhanced Oil Recovery
Authors: Hosseini-Nasab S. M. , Padalkar C.. , Battistutta E.. , Zitha P. L. 
Published: August 2015

Abstract
Alkaline-Surfactant-Polymer (ASP) flooding is potentially the most efficient chemical EOR methods. It yields extremely high incremental recovery factors in excess of 95% of residual oil for water flooding. The current opinion is that such extremely high recoveries can only be achieved at optimum salinity conditions, i.e. for the Winsor type III micro-emulsion phase characterized by an ultra-low interfacial tension (IFT). This represents a serious limitation since several factors including alkali-rock interaction, initial state of reservoir water and salinity of injected water may shift the ASP flood design to either under or over optimum conditions.
A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS), in natural sandstone cores varying salinity from under-optimum to optimum conditions indicated that indeed high recovery factors can be obtained also at under-optimum salinity conditions (see parent paper in this conference by Battistutta et al (2015).
In this paper a mechanistic model is developed to explore the causes behind the observed phenomena.
The numerical simulations were done using the UTCHEM research simulator (University of Texas at Austin) together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulator with a robust phase behaviour modelling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration at effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant and polymer profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flood. Due to the uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating the ASP flood at a particular salinity region. Moreover, simulation results demonstrate for the crude oil with considerably low acid number, the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities less than optimal salinity. The results provide a basis to perform better modelling of the under-optimum series of experiments and optimizing the design of ASP floods methods for the fields scale with more complicated geochemical condition.
Estimation of Near-Miscibility Conditions Based on Gas-Oil Interfacial Tension Calculations
Authors: Al Riyami Mohamed , Rao Dandina N. 
Published: August 2015

Abstract
Minimum Miscible Pressure (MMP) is a critical parameter in the design of gas injection EOR projects. Several experimental and analytical methods have been proposed in the literature for determining MMP. For example, slim-tube experiments, method of characteristic (MOC) and numerical-simulation/cell-to-cell methods. The majority of these methods have limitations of complexity, long duration and/or high costs. Hence there is a need for alternative approaches. This paper presents a simple method for estimating near-miscibility pressures that is based on a gas-oil interfacial tension calculation procedure. The method assumes near miscibility conditions at low interfacial tensions and relies only on using a cubic equation-of-state (EOS) and the Parchor model. This method enables rapid calculation of MMPs for multiple component gas-oil systems. The method was validated against Zick fluid system and tested in a number of gas-oil systems. We also present a detailed analysis of the quality and compatibility of Whitson characterization with the IFT based method, where we consider a broad range of 12 gas-oil systems, for which PVT (composition, CCE and CV) and gas injection data are available (swelling test, slim tube test). We explore the impact of using swelling test data and slim tube data to tune the EOS on the calculated MMP using IFT based method. The results show that MMP estimation using our IFT based method is fast, easy to implement and reasonably accurate.
Reitbrook Case Study: Enhancing Oil Recovery Through the Underground Gas Storage Activity
Authors: Perreaux M.. , Bontemps C.. , Egermann P.. 
Published: August 2015

Abstract
Reitbrook oil field, located in the North of Germany, has produced oil since 1937 and has an impressive production history of more than 77 years. Reitbrook field life can be divided into three main periods: Oil Production (1937-1963), Gas Blowdown (1963-1973) and Underground Gas Storage (UGS) (1973-2014).
The oil production did not stop during the Gas Storage period. On the contrary, the gas injection and withdrawal periods linked to the UGS activity allowed to enhance the oil production of this mature asset. After a brief presentation of the field, the specific mechanisms enhancing the oil production during the UGS period will be detailed and compared to the traditional gas injection technique.
Reitbrook is a shallow (top reservoir at 640 m/bsl) oil field with an initial reservoir pressure of 81 bars and a specific oil gravity of 22°API. Some uncertainty remains on the STOOIP which is in the 31-41 106 Sm3 range. Before being converted into an UGS in 1973, the field had a cumulative oil production of 2.35 106 Sm3, corresponding to a recovery factor around 6.5%. During the UGS period, circa 0.5 106 Sm3 of additional oil has been produced, increasing the recovery factor from 6.5% to 7.8%. The increase in oil production during the UGS period is linked to various physical mechanisms, both at the pore scale and at the reservoir scale. The conversion of an oil field into an UGS makes a specific EOR process which can be contemplated to extend the life of a mature oil field.
Through Reitbrook case study, the oil production mechanisms linked to the UGS activity will be presented, showing that this combination could be considered as an effective EOR technique. The conversion of a mature oilfield into an UGS while enhancing its oil production is also interesting from an economic perspective since it cumulates the value of the increase in oil recovery and the value of the gas storage activity while sharing the cost of gas compression / treatment and the benefits from the wells already in place. In addition, the implementation of such projects also allows to extend the economic life of installations and to postpone the decommissioning costs.
Stability Improvement of CO2 Foam for Enhanced Oil Recovery Applications Using Polyelectrolytes and Polyelectrolyte Complex Nanoparticles
Authors: Kalyanaraman Nishkriya , Arnold Cameron , Gupta Aadish , Tsau Jyun Syung , Barati Reza 
Published: August 2015

Abstract
CO2 foam for enhanced oil recovery applications has been traditionally used in order to address mobility control problems occur during CO2 flooding. However, the supercritical CO2 foam generated by surfactant has a few shortcomings such as loss of surfactant to the formation due to adsorption, and lack of a stable front in the presence of crude oil. These problems arise due to the fact that surfactants dynamically leave and enter the foam interface. We discuss the addition of polyelectrolytes and polyelectrolyte complex nanoparticles to the surfactant solution in order to stabilize the interface using electrostatic forces with a view to generate stronger and longer lasting foams.
An optimized ratio and pH of the polyelectrolytes was used to generate the nanoparticles. Thereafter we studied the interaction of the polyelectrolyte-surfactant CO2 foam and the polyelectrolyte complex nanoparticle-surfactant CO2 foam with crude oil in a high pressure, high temperature static view cell. The nanoparticle-surfactant CO2 foam system was found to be more durable in the presence of crude oil. Understanding the rheology of the foam becomes crucial to determine the effect of shear on the viscosity of the foam. A high pressure high temperature rheometer setup was used to shear the CO2 foam for the three different systems and the viscosity was measured with time. It was found that the viscosity of the CO2 foams generated by these new systems of polyelectrolytes were slightly improved than the surfactant generated CO2 foams. Core flood experiments were conducted in the absence and the presence of crude oil to understand the foam mobility and the oil recovered. The core flood experiments in the presence of crude oil show promising results for the CO2 foams generated by nanoparticle-surfactant and polyelectrolyte-surfactant systems. This paper also reviews the extent of damage if any, that could be caused due to the injection of nanoparticles.
An Innovative Approach to Make HPAM an Effective Solution to Optimize the Low Salinity ASP Application in Caracara Sur Field, Colombia - Field Case
Authors: Cubillos H.. , Stofferis M.. , Montes J.. , Rodriguez R.. , Prieto C.. , Romero P.. , Blin N.. , Panadero A.. 
Published: August 2015

Abstract
To ensure a technically and economically viable chemical Enhanced Oil Recovery (cEOR) project in the Caracara Sur Field (Llanos Basin Colombia), several challenges were faced. One of the challenges described in a previous work (Cubillos et al. 2013), is the design of an efficient chemical formulation stable at reservoir conditions. Comprehensive laboratory work has been undertaken, resulting in an Alcali Surfactant Polymer (ASP) formulation containing hydrolysed polyacrylamide (HPAM) as a mobility control agent. HPAM is the most used polymer in the oil industry thanks to its low cost and availability in high quantities. However, initially it was not clear that HPAM efficiently worked for Caracara Sur, because HPAM properties limits its efficient application to low temperatures (&lt;80 °C) and low-to-moderate salinity reservoirs.
In this paper, we present the laboratory work that lead to find an innovative solution founded on the synergy between the formation water properties (low salinity) and high temperature environment in the Caracara Sur Field. The study focused on the polymer screening process, rheological properties of HPAM with the low salinity brine of Caracara Sur, the HPAM performance in porous media and chemicals to enhance its thermal stability. This work is only focused on the polymer selection and the synergy between low salinity brine and polymer flooding.
The main results show that the developed formulation for the Caracara Sur reservoirs is a viable cEOR alternative. By injecting low salinity brine and HPAM with the right mix of other chemical components, it is possible to drastically reduce the cost of cEOR, whilst maintaining the same efficiency even at higher reservoir temperature. As a final product, an optimal ASP formulation has been developed and successfully tested both at laboratory and field conditions.
How Viscoelastic Polymer Flooding Enhances Displacement Efficiency
Authors: Clarke A.. , Howe A. M. , Mitchell J.. , Staniland J.. , Hawkes L. A. 
Published: August 2015

AbstractIncreasing flooding solution viscosity with polymers provides a favourable mobility ratio, compared to brine flooding, and hence improved volumetric sweep efficiency. Flooding with a polymer solution exhibiting elastic properties has been reported to increase displacement efficiency, resulting in a sustained doubling of the recovery enhancement compared to that with conventional viscous polymer flooding (SPE-144294 (Wang, et al., 2011)). Flooding with viscoelastic polymer solutions is claimed to increase recovery more than expected from changes in capillary number alone (SPE-127453 (Wang, et al., 2010)). This increase in displacement efficiency by viscoelastic polymers is reported to occur due to changes in the steady state flow profile and enhancements in oil stripping and thread formation. However, within the industry there are doubts that a genuine effect is observed, or that improvements in displacement efficiency occur with field-applicable flow regimes (SPE-169681 (Vermolen, et al., 2014)).In this work, we show a different mechanism by which viscoelastic polymer solutions provide improvements in displacement efficiency, and demonstrate that these effects may be obtained at field-relevant flow rates. Our observations implicate an effect previously unrecognised in this context. Furthermore, this underlying mechanism explains both the enhanced capillary desaturation curves and the observation of apparent flow thickening (SPE-129200 (Seright, et al., 2011), SPE-113620 (Delshad, et al., 2008)) for these viscoelastic solutions in porous media. The work contrasts experiments on flow and recovery using viscous and viscoelastic polymer solutions. The circumstances under which viscoelasticity is beneficial are demonstrated. The findings are applicable to the design of formulations for enhanced oil recovery by polymer flooding.A combination of core flooding, micromodel flow, and rheometric studies are presented. The results include single-phase and multi-phase floods in sandstone cores. Polymer solutions are viscoelastic (partially hydrolysed polyacrylamide, HPAM) or viscous (xanthan). The effect of molecular weight, flow rate, and concentration of the HPAMs are described. The data lead us to suggest an alternative mechanism that may be used to explain the observations of improved displacement efficiency and why the improvement is not seen for all viscoelastic polymer floods.
Nano Spherical Polymer Pilot in a Mature 18° API Sandstone Reservoir Water Flood in Alberta, Canada
Authors: Irvine Randy , Davidson John , Baker Mark , Devlin Ryan , Park HuiJune 
Published: August 2015

Abstract
A previous SPE paper1 described the operational challenges associated with hydration and viscosity control of linear long-chained hydrolyzed Polyacrylamide (HPAM) using produced formation water from the Lower Mannville (Sparky) formation. Production results were disappointing, but the Pilot Project was considered technically successful.
Reservoir heterogeneity in tight laminated sandstone reservoirs impacts the efficiency of water flooding and complicates the application of chemical Enhanced Oil Recovery (EOR) methods for conformance control. In the case of the Wain B Pilot Project, the use of HPAM for mobility and conformance modification in the tight saline Mannville reservoir was considered risky. However, at the time there were no apparent viable chemical flood alternatives. The Operator decided to proceed with a relatively large pilot project, as introduced in the aforementioned SPE 154050 Paper1. The rate of production uplift achieved was considered economically unsuccessful in the time frame expected for capital projects. Polymer injection was ramped down in late 2012, before the designed pore volume displacement had been achieved, and the injection wells were returned to water injection. Since then, an uplift in oil production has been realized. Nevertheless, a different type of chemically assisted EOR technology was required for the range of tight reservoirs under consideration.
This current SPE paper will compare production results of that previous Wain B Polymer Pilot Project, which used HPAM 3630s, with early results from a nano spherical polymer (nanosphere) pilot project in the adjacent and similar Scovil Pool in East-Central Alberta, Canada.
Visualisation of Light Oil Mobilisation in ASP Core Floods Using X-Ray CT Imaging
Authors: van Batenburg D.W.. W. , Berg S.. , Oedai S.. , David L. L. , Siemens A. O. , Elewaut K.. 
Published: August 2015

AbstractThis paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Berea sandstone outcrop material with diameters of approximately 7.55 cm and lengths of 27.5 and 99 cm. Two light crude oils with in-situ viscosities of 1.3 cP and 3.2 cP were used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process.In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance.One important observation from the experiments is that there exist a typical fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The tail production observed in many ASP core floods is a consequence of the formation of this fingering zone.Effluent analyses conducted on the produced fluids from the long core experiments showed an instantaneous build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail production.Another important observation is that a characteristic self-similar cross-sectional averaged oil saturation profile develops during ASP injection after water flood in cores containing non reactive light crude oil.The implications of the self-similarity of the saturation profiles in combination with the observation that the surfactant propagation is retarded with respect to the polymer propagation results in a polymer flood ahead of the ASP-slug and a corresponding characteristic oil production profile. The characteristics of this process can be captured with an extended fractional flow approach that utilizes three fractional flow curves: one for the ASP-slug, one for polymer, and the original fractional flow curve for oil-water.