bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Oil Gravity and Pore Volume Injected (PVI) of Steam to PVI of Foam During Enhanced Oil Recovery by Steam-CO2-Foam Flooding
Authors: Daraei H. Nejatian , Sahraei E.. , Solouk A..
Published: August 2015

In spite of CO2mobility reduction during CO2and surfactant solution co-injection, CO2-foam flooding in heavy oil reservoirs has relatively poor sweep efficiency due to the high viscosity the oil. Therefore, reducing the oil viscosity is necessary to improve CO2-foam sweep efficiency. For this reason, steam is injected initially during steam-CO2-foam flooding to reduce oil viscosity. Displacement process is followed using CO2and surfactant solution co-injection.

In our previous experimental study, in order to highlight the potential of steam-CO2-foam flooding, three different oil recovery experiments were conducted using medium heavy crude oil (19 °API), including CO2-foam flooding after water flooding, CO2-foam flooding and steam-CO2-foam flooding. The results showed that steam-CO2-foam flooding increases oil recovery dramatically by simultaneous mechanisms such as oil viscosity reduction by steam, CO2dissolution in oil and emulsification by steam and surfactant. Furthermore, the effect of high surfactant concentration slug injection on steam-CO2-foam flooding performance was investigated. The results showed that slug causes the formation of viscous micro emulsions in front of CO2-foam flood and improves CO2-foam sweep efficiency.

In this paper, the effects of oil gravity and pore volume injected (PVI) of steam to PVI of foam on the oil recovery during steam-CO2-foam flooding have been studied. The experiments are conducted using heavy oil (12 °API) and sand pack models under reservoir conditions of 1550 psi and 131°F.

In order to investigate the effect of PVI of steam/PVI of foam ratio on the oil recovery, three different oil recovery scenarios have been conducted using heavy crude oil, including CO2-foam flooding only, steam-CO2-foam flooding including 0.14 PVI of steam/PVI of foam ratio and steam-CO2-foam flooding including 0.34 PVI of steam/PVI of foam ratio. The results show that in spite of decreasing oil recovery by decreasing API gravity of the oil during steam-CO2-foam flooding, increasing PVI of steam improves oil recovery.

The steam-CO2-foam flooding process has the following benefits. (1) Combination of steam injection and CO2-foam flooding as a novel enhanced oil recovery (EOR) method to achieve favorable oil recovery. (2) The applicability of this EOR method in heavy and medium heavy oil reservoirs.
Case Study on In-Depth Blocking for Thermal Recovery by Steam Stimulation in Heavy Oil Reservoirs
Authors: You Qing , Wang Huan , Dai Caili , Liu Yifei , Fang Jichao , Zhao Guang , Zhao Mingwei , Wang Kai
Published: August 2015

The conventional blocking agents are hard to solve the problem of steam channeling during steam injection. In order to increase sweep volume and improve oil recovery, the in-depth blocking agents for conformance control are proposed and developed according to temperature gradient in the stratum when injecting steam. The in-depth blocking agents consist of gel system, organic/inorganic cross-linking system and inorganic curing system with different applicable temperature 60~110°C, 120~160°C and 170~300°C. The gel system with temperature resistance is composed of non-ion polyacrylamide and organic cross-linker. The organic/inorganic cross-linking system is composed of organic resin, silicide and stabilizer. The inorganic curing system is composed of superfine cement and stabilizing Na-bentonite. In this paper, the temperature distribution of heterogeneous reservoirs during the process of steam huff and puff is simulated by CMG. According to the above temperature distribution, these blocking agents are separately used for remote zone, transition zone and near wellbore zone of steam injection well. Sandpack flood tests indicate that the in-depth blocking agents have excellent blocking performance. Furthermore, the in-depth blocking agents have been applied to two injection wells in Bin'nan oilfield. After oilfield pilot test, steam injection pressure and daily oil production increased, and the input-output ratio increased to 1:3. The success of oilfield test confirms that the in-depth blocking agents are efficient to control steam channeling.
Solvent-Assisted Start-Up of SAGD in Shallow Heavy Oil Reservoirs
Authors: Wu Yongbin , Li Xiuluan , Shen Dehuang , He Wanjun , Liu Xueqi
Published: August 2015

Effective communication between the injector and producer with a reasonable conformance during SAGD start-up phase is crucial for the success of SAGD conversion and the following ramp-up phase. The start-up operation normally relies on heat conduction mechanism to establish heat and fluid communication between the wells. For super heavy oil reservoirs in Fengcheng project in China, since the pay zone has low thermal conductivity and extremely high oil viscosity, establishing the temperature profile required for SAGD conversion using conduction as the only heating mechanism is not efficient and can take 150 to 180 days to achieve. In order to shorten the circulation time and accelerate the ramp-up phase after SAGD conversion, an approach using solvent injection with steam simultaneously to enhance injectivity was successfully designed and implemented.

This paper reviews the design criteria, tests the thermal properties of cored samples, selects the typical wellpair based on geological modeling results, carries out the reservoir engineering design of solvent injection using CMG-STARS, and discusses the implementation performance of warm solvent injection in the start-up phase of a pilot wellpair in Fengcheng project. It also compares production responses of solvent-treated wellpair with other wellpairs with comparable reservoir properties in the same pad by conventional start-up to evaluate the performance of the designed pilot.
Laboratory Evaluation of Inter-Well Partitioning Tracers for the Determination of Remaining Oil Saturation after ASP Flooding
Authors: Austine J.. , van Batenburg D. W. , Southwick J. G. , Zarubinska M. A. , Paramanathan S.. , Bouwmeester R. C. , Kechut N. I. , Viig S. O. , Haugen O. B. , Brandvoll Ø..
Published: August 2015

Alkaline Polymer Surfactant (ASP) flooding is an Enhanced Oil Recovery (EOR) technique aiming to mobilise remaining and residual oil. Estimating the average oil saturation prior to and post ASP flooding is a recognised challenge, but is vital to the evaluation of an ASP pilot. The use of oil-water partitioning tracers is a method to determine the average oil saturation in the water-swept regions between wells. The implementation of partitioning tracer technique is known in the industry to evaluate effectiveness of waterfloods, but its applicability in ASP flooding is a topic of investigation due to additional complexities. Often, the partition coefficients of tracers depend on salinity of the aqueous phase. It is equally important to know how the presence of polymer and surfactant may influence the behaviour of partitioning tracers.

Laboratory study has been performed to analyse the behaviour of partitioning tracers prior to and post ASP injection for a field that is currently undergoing sea water injection and is being evaluated for ASP flooding later in the field life. A group of six oil-water partitioning tracers have been included in the study. Batch (bottle tests) and dynamic (core flood) experiments were performed to evaluate the partitioning behaviour of the tracers. The residual oil saturation to water (Sorw) before ASP flooding was determined using pulse injections of tritium labelled water (HTO). Several passive tracers were also injected in the core floods and their retention times were compared with that of HTO.

Herein we describe evaluation of oil saturation, through the tracer responses, over a range of brine compositions such as soft brine, sea water, ASP and polymer solutions. Batch studies indicate the dependency of the partitioning of the tracers on brine salinity. The results of core floods show earlier breakthrough of anionic passive tracers in comparison with HTO suggesting possible rock/fluid interactions for the anionic passive tracers. The residence time distribution of HTO measured before, during and after the ASP flooding illustrates that the flow paths available for water were changed during ASP flooding.

The paper highlights the importance of good laboratory experimental protocols using a more accurate passive tracer such as tritium labelled water. The results from the experiments draw attention to the uncertainties associated with the flow of tracers under changing salinity and chemical composition.
Contribution of Pore-Shape to the Polymer Apparent Viscosity
Authors: Kawale D.. , Boukany P. E. , Kreutzer M. T. , Rossen W. R. , Zitha P. L.
Published: August 2015

Polymer injection is a widely used enhanced oil recovery technique. Optimizing this process requires a thorough understanding of the nature of polymer flows through the porous medium. The current approach involves using an apparent viscosity, as described by the Darcy's law. Such an apparent viscosity is an effective parameter which accounts for effects introduced by the porous medium and the bulk rheology of polymer solutions. These effects include excluded pore volume, inaccessible pore volume, adsorption/retention, shear-thinning, shear-thickening due to converging-diverging channels, non-uniform flow channels, and viscoelasticity. To explain the apparent shear-thickening behaviour in porous media, the existing models use an ad hoc hypothesis; that is, the experimental evidence for these effects is missing. The objective of this study is to obtain a mechanistic picture. We study the effect of pore shape on the apparent viscosity, as the shear rate is varied.

Microfluidic devices containing 2D planar porous media with different pore shapes are fabricated using lithography techniques. The devices are essentially periodic arrays of obstacles in square and diamond layouts. Simultaneously measuring the pressure drop while visualizing the flow field allows us to map the flow-field variations on an apparent-viscosity map. We visualize the flow by seeding the polymer solution with fluorescent particles. A time-steady flow field is observed in the shear thinning region, whereas, flow instabilities are observed at the range of shear rates where the shear thinning region ends and the shear thickening region starts. This suggests that the shear-thickening region is somehow connected to those instabilities.

Power spectral density is calculated by applying Fast Fourier Transform to the pressure drop time-series data. The power spectral density in the shear-thickening region reveals power law scaling. This power law scaling indicates that the energy from large vortices is gradually transferred to smaller vortices, until it is dissipated as thermal energy. Such an energy cascade system is a typical characteristic of large Reynolds number turbulent flow. However, in our experiments the Reynolds is low, whereas the Weissenberg number is large. Under these conditions, the flow instabilities that we observe originate from an interplay of the shear thinning viscosity and the elastic stresses in the polymer solution.
Simulation for High Viscoelasticity Polymer Flooding Pilot in LMDN4-4 Block of Daqing Oilfield
Authors: Chen Guo , Wei Changqing , Han Xu , Han Peihui , Ma Moran , Zhang Xinliang , Lu Kewei
Published: August 2015

Daqing Oilfield has carried out a high viscelasticity polymer flooding pilot in LMDN4-4 Block, demonstrating that the high viscoelasticity polymer flood has bigger capability to further increase oil recovery over moderate viscoelasticity polymer flood. The bulk viscosity of produced polymer solution taken from a monitoring well is around 140 mPa.s, using the high viscosity data as input parameters to conduct history matching by commercial simulator indicated that injection pressure from simulation is much higher than that from observation data, resulting from the higher bulk viscosity together with having no take polymer elasticity process mechanism into account. Therefore, how to successfully conduct simulation for high viscoelasticity polymer flood is a big challenge.

We have conducted a series of lab and reservoir engineering studies to further realize and characterize the polymer elasticity process mechanism so as to achieve a good history matching. Polymer flooding capillary desaturation curve at different polymer elasticity level is established, relative permeability curve for high viscoelasticity polymer flooding is obtained, and the flowing viscosity in porous media for polymer solution with high viscoelasticity is estimated based on the polymer flooding performance data. All these research results provide very accurate input parameters for the simulation model, running by an in-house simulator that has incorporated polymer elasticity process mechanism model.

Based on these newly methods above, the production performance for the high viscoelasticity polymer flood pilot has been matched very well, showing that: (1) High viscoelasticity polymer flood simulation should take the polymer elasticity process mechanisms of reducing residual oil saturation and increasing oleic phase relative permeability into account, (2) It is the flowing viscosity of polymer solution that acts on the flow process in polymer flooding rather than the bulk viscosity, and the flowing viscosity is dramatic lower than the bulk viscosity for high viscoelasticity polymer solution.
Toward an Alternative Bio-Based SP Flooding Technology: I. Biosurfactant Evaluation
Authors: Luque Alanis P. A. , AlSofi A. M. , Wang J.. , Han M..
Published: August 2015

Surfactant-polymer (SP) flooding is one of the most promising methods in enhanced oil recovery (EOR), especially where an existing waterflooding infrastructure is in place. This work is part of a broader research theme in which our group is evaluating the potential of biochemicals for chemical enhanced oil recovery (CEOR). Biosurfactants belong to a diverse group of surface-active chemicals generated by microbial fermentation. Recently, the use of biosurfactants in a CEOR formulation has gained greater attention due to their biodegradability, low toxicity, and effectiveness at high temperature and salinity. In this work, we evaluate the potential of a particular biosurfactant for CEOR application in a carbonate reservoir that is characterized by high temperature and high salinity. We evaluate the biosurfactant compatibility, interfacial tension (IFT) reduction, stability, and adsorption. We benchmark its performance against a synthetic surfactant that had previously proved potent. Compatibility with the field brines (injected and connate) is investigated by observation of solution appearances. IFT reduction is measured using a spinning drop tensiometer. IFT, after prolonged heating, was also measured to investigate the stability of the biosurfactant. Finally, static adsorption tests were conducted using crushed rock samples where changes in biosurfactant concentration, and adsorption, was inferred using a total organic content analyzer.

The biosurfactant showed excellent compatibility with field brines at reservoir temperature. It exhibited low static adsorption of 0.65 mg/g. Most importantly, at a concentration of 2000 ppm, the biosurfactant resulted in a very low IFT in the order of 10−2 mN/m. The biosurfactant resulted in an IFT reduction that is comparable to that achieved with the benchmark surfactant. A coreflood, where the biosurfactant was injected in a tertiary mode, demonstrated an additional production of around 6.5% OOIC (original oil in the core). The expected performance of this biosurfactant was further compared to the benchmark surfactant using numerical simulation. Core-scale simulation results suggest the biosurfactant can yield incremental recoveries that are comparable to those obtained using the benchmark surfactant. At the core-scale, a tertiary SP flood, in which a biochemical surfactant is used, can yield an additional production of around 17% OOIC. The results discussed in this paper constitute the first step toward developing an alternative bio-based SP flooding technology for carbonate reservoirs with harsh conditions.
Predicting Interfacial Tension Using Advanced Meso-Scale Modelling Technique
Authors: Kamal Muhammad Shahzad , Matar Ali-Al , Sultan Abdullah S , Hussein Ibnelwaleed A
Published: August 2015

Surfactant EOR is an attractive method to recover residual oil from light oil reservoirs. Selection of suitable surfactant for a particular reservoir conditions is a challenging and time consuming task. Surfactants have to be evaluated through a series of evaluation steps which include: compatibility, phase behavior, thermal stability, interfacial tension (IFT), adsorption and core flooding. IFT measurements are challenging and time consuming particularly at high-temperature. Due to dynamic nature of IFT it may take several hours to reach an equilibrium value. Moreover, commercially available techniques rely on the shape of the oil drop which is not necessarily to be exactly cylindrical. In this paper a meso-scale molecular modelling technique called Dissipative Particle Dynamics (DPD) will be used to predict IFT of water/oil/surfactant ternary system.

In this technique different molecules of similar structures are lumped into single bead. Beads don't have fixed properties being composed of different elements. Bead properties need to be determined either using molecular simulation or by experimental values. In this work bead-bead repulsion parameters were calculated using molecular simulations. Hexane, nonane and pentadecane were used as model crude oil. Sodium dodecyl sulphate was used as surfactant.

As different molecules are lumped into single beads, faster evaluation of surfactants can be performed. The interfacial properties like interface thickness and interfacial tension and their dependence on oil types, surfactant types, oil/water ratio, surfactant concentration and surfactant chain length at particular temperature and pressure were investigated. Good qualitative as well as quantitative agreement of the modelled properties was obtained with experimental data. Detailed methodology, theory and results will be discussed in the paper. DPD technique is a novel way for initial screening of surfactants and can reduce experimental tests and time.
Pore Scale Visualization during Carbonate Heavy Oil Recovery: Surfactant Alternating CO2 Foam/Polymer Enhanced Foam Flooding
Authors: Telmadarreie Ali , Trivedi Japan
Published: August 2015

Carbonate reservoirs hold significant reserves of heavy crude oil that can be recovered by non-thermal processes. Chemical, gas, water, and solvent injections are the main methods for carbonate heavy oil recovery. Chemical enhanced oil recovery (EOR) from oil-wet carbonate reservoirs has been focused on using surfactants to change the wettability and enhance water imbibition into matrix blocks. Due to the fractured nature of carbonate formations, many advantages of these production methods are usually contrasted by their low recovery factor. Alternative processes are therefore needed to increase oil sweep efficiency from the matrix. Foam/polymer enhanced foam (PEF) injection has gained interest in conventional heavy oil recovery in recent times. However, the oil recovery process by foam injection, especially by PEF, is less understood in fracture heavy oil carbonate reservoirs.

This paper introduces a new approach to access the heavy oil from fractured carbonate reservoirs. CO2 foam and CO2 PEF were used to decrease oil saturation after surfactant flooding. Three types of surfactants (nonionic, anionic and cationic) were used for both surfactant and foam flooding. A specially designed fractured micromodel was used to visualize the pore scale phenomena during CO2 foam/PEF injection. In addition, the static bulk performances of foam/PEF were analyzed in the presence of heavy crude oil. A high definition camera was utilized to capture high quality images.

The results showed that, in both static and dynamic studies, the PEF had higher stability than that of foams. Nonionic surfactant generated the least stable foam in the presence of crude oil. Surfactant flooding slightly increased the oil recovery from matrix after water injection. This was more evident in the case of CTAB surfactant with highest imbibition rate. This study showed that there is an acceptable relationship between the results of foam static stability and its dynamic performance in porous media. DDBS foam had higher static stability, which resulted in the highest oil recovery in dynamic experiments. Observation through this study proved that stable foam/PEF bubbles can significantly push the injected fluid toward untouched parts of the porous media and increase the oil recovery. Due to the liquid viscosity enhancement and bubble stability improvement, the effectiveness of PEF in heavy oil sweep efficiency was much higher than that of conventional foams. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. The results of pore scale visualization improved understanding of the heavy oil recovery process by CO2 foam/PEF flooding from fractured reservoirs.
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

We 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.
Numerical Modelling of Microbial Enhanced Oil Recovery Process Under the Effect of Reservoir Temperature, pH and Microbial Sorption Kinetics
Authors: Sivasankar P.. , Govindarajan Suresh Kumar
Published: August 2015

The present work numerically investigates the effect of reservoir temperature and pH on microbial growth and its transport within the reservoir which undergoes the reversible sorption kinetics. Further, the present work also studies the influence of reservoir temperature and pH on changes in interfacial tension between oil and water, capillary pressure and its impact on microscopic oil displacement efficiency. The microbe used is strain of Bacillus sp and the nutrient supplied to microbe is molasses. For this purpose, a novel mathematical model is developed which describes the coupled multiphase fluid flow and multispecies reactive transport in porous media which occurs during the MEOR process. Moreover, in the present work, the first order Monod kinetics equation is expressed as a function of temperature and pH which dictates the microbial growth rate. The developed mathematical model is sloved numerically by finite volume discretization technique and the results are found to be numerically stable and validated with the experimental results. The numerical data used for validation and for numerical simulation studies are presented. The results suggest that the oil displacement efficiency increases as the reservoir temperature and pH approaches the optimum temperature and pH required for microbes to reach its maximum growth. The present numerical model may be applied as an effective screening tool before the application of MEOR process and also serves as a reservoir simulator tool to predict the performance of MEOR process.
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

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

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

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

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

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

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 (<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

Increasing 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

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

This 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.
Coupled Geochemical-Reservoir Model to Understand the Interaction Between Low Salinity Brines and Carbonate Rock
Authors: Nasralla Ramez A. , Snippe Jeroen R. , Farajzadeh Rouhi
Published: August 2015

Low salinity waterflood (LSF) is a promising technology for improving oil recovery. Several laboratory studies have demonstrated the potential of LSF to alter the rock wettability and improve oil recovery in carbonate reservoirs. Some studies have considered calcite dissolution as a mechanism behind the wettability alteration by LSF in carbonates. Moreover, the interaction between rock and injected brine can lead to change in the injected brine composition and pH. Therefore, it is important to better understand the interaction between injected brine and carbonate rock to de-risk the LSF technology for field applications.

A numerical model was developed by coupling a reservoir simulator (Shell in-house Simulator, MoReS) with a geochemical model (PHREEQC) to study the interaction between the injected brine and carbonate rock. Calcite is assumed to be the rock mineral to represent most of carbonate reservoirs. Two reservoir rock models are presented: one for coreflood scale and another for field scale. To mimic reservoir condition, the rock is saturated with formation brine (180 g/l) and several brines with different salinity and composition are injected. The model is calibrated to the published experimental data in the literature. Both Local Equilibrium and Kinetic approaches are used to model the interaction between injected brines and rock. Furthermore, the impact on calcite dissolution is examined against various parameters such as brine composition and pH, and temperature.

The model results indicate that interaction between calcite and brine can reach equilibrium quickly. As a result, LSF may dissolve calcite from part or the whole core during flooding experiments depending on the kinetics of the interaction. However at field scale, the calcite dissolution occurs only in the area near the injector. This suggests that if calcite dissolution is one of the LSF mechanisms, this mechanism will not contribute to improving oil recovery at field scale. Although calcite dissolution can occur only near the injector, it can still change the composition and pH of the injected brine, which may have an impact on the oil recovery. The increase in salinity due to calcite dissolution in not significant in absence of CO2, but the brine pH may reach 8-9.