bluuebunny/crossref_metadata_2025 huggingface dataset:
Surfactant Systems for EOR in High-Temperature, High-salinity Environments
Authors: Puerto Maura , Hirasaki George J. , Miller Clarence A. , Barnes Julian R.
Published: July 2010

A systematic study was made of phase behavior of alkoxy glycidyl sulfonates (AGSs). These surfactants were screened with either NaCl-only brines or NaCl-only brines and n-octane at WOR ~1 for temperatures between approximately 85°C and 120°C. All test cases were free of alcohols and other co-solvents. Classical Winsor phase behavior was observed in most scans with optimal salinities ranging from less than 1% NaCl to more than 20% NaCl for AGSs with suitable combinations of hydrophobe and alkoxy chain type (ethylene oxide or propylene oxide) and chain length. Oil solubilization was high, indicating that ultralow interfacial tensions existed near optimal conditions. The test results for 120°C at WOR~1 have been summarized in a map, which might provide a useful guide for initial selection of such surfactants for EOR processes. Saline solutions of AGSs separate at elevated temperatures into two liquid phases (cloud point phenomenon), which may be problematic when they are injected into high-temperature reservoirs. An example is provided which indicates that this situation can be alleviated by blending suitable AGS and internal olefin sulfonate (IOS) surfactants, these being within Shell Chemical's ENORDETTM range of surfactants for EOR. Synergy between the two types of surfactant resulted in transparent, single-phase aqueous solutions for some blends, but not for the individual surfactants, over a range of conditions including in synthetic seawater. Such blends are promising because both AGS and IOS surfactants have structural features that can be adjusted during manufacture to give a range of properties to suit reservoir conditions (temperature, salinity and crude oil type).
History Matching Channelized Reservoirs Using Reversible Jump Markov Chain Monte Carlo Methods
Authors: Xie Jiang , Mondal Anirban , Efendiev Yalchin , Mallick Bani , Datta-Gupta Akhil
Published: July 2010

A novel method is presented for history matching and uncertainty quantification for channelized reservoirs using Reversible Jump Markov Chain Monte Carlo (RJMCMC) methods. Our objective is to efficiently sample realizations of channelized permeability fields conditioned to production data and permeability values at the wells.

In our approach, the channelized permeability field is reparameterized using the discrete cosine transform (DCT). The parameters representing the channel structure are the coefficients in truncated frequency domain. The parameter space is searched using a RJMCMC, where the dimension of the parameter space is assumed to be unknown. For each step of the RJMCMC, the dimension of the uncertainty space can be increased or decreased according to a prescribed prior distribution. This flexibility in the parameter dimension allows an efficient search of the uncertainty space. To speed up the computation and improve the acceptance rate of the RJMCMC algorithm, we employ two-stage methods whereby coarse-scale simulations are used to screen out the undesired proposals. After simulations, multi-dimensional scaling and cluster analysis are used to select realizations from the accepted models to adequately represent the diversity of the models.

We demonstrate the effectiveness of the RJMCMC algorithm using both 2D and 3D examples involving waterflood history matching. The 2-D example shows that the RJMCMC algorithm can successfully match the data and identify the orientation of the channels in the reference model. The 3-D results show that the proposed algorithm can determine the large-scale features of the reference channelized permeability field based on the production data. The MCMC algorithms naturally provide multiple realizations of the permeability field conditioned to well and production data and thus, allow for uncertainty quantification in the forecasting.
On the Relationship between Completion Design, Reservoir Characteristics, and Steam Conformance Achieved in Steam-based Recovery Processes such as SAGD
Authors: Wei Wei , Gates Ian D.
Published: July 2010

With continuing decline of conventional crude oil reserves, there is higher demand for developing and producing heavy oil and bitumen resources. In Alberta, Canada, there are over 170 billion barrels of recoverable bitumen in oil sands. The two main thermal technologies being used to produce are Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). For Athabasca reservoirs, SAGD is the method of choice since the oil has low solution gas. One key factor that controls the success of these methods is steam conformance – the ability to control the distribution of steam within the oil column. In this research, thermocouple data from the Surmont SAGD pilot project together with reservoir geology are analyzed to examine steam conformance and its impact on process performance (oil rate, recovery factor, and steam to oil ratio). The data is analyzed to generate a simple correlation between reservoir geology and operating pressure to predict vertical steam conformance versus time. The results demonstrate that the reservoir geology, operating pressure, and well completion design all affect steam conformance in the reservoir. Also, the distribution of steam flow and pressure within the well impacts steam conformance in the reservoir. An analysis of the A wellpair of the Surmont SAGD pilot suggests that the distribution of steam flow in the well contributes largely to the non-uniform steam conformance along this wellpair.
The Displacement of Heavy Oil From Diatomite Using Hot Water and Steam
Authors: Dietrich J. K.
Published: July 2010

Results of diatomite core displacement tests designed to study the effects of fluid system, rock type, stress and temperature are presented here. Two heavy oils (12.3 and 17.8°API) were evaluated using water varying in temperature from 91 to 550°F and steam at either 330 or 550°F. Three amorphous Opal-A and 1 crystalline Opal-CT rock types were tested at effective stress levels varying from 450 to 1100 psi. Measurements are provided for both dead and live-oil density and viscosity, live-oil thermal expansion, and remaining oil saturation as a function of temperature and fluid displacement type and phase.

Hot-water flooding at about 200°F as compared to 100°F was shown to be capable of increasing oil displacement efficiency from about 30 to 60% of original oil-in-place. Hot-water flooding at either 330°F or 550°F was shown to be capable of further increasing displacement efficiency to about 70% of OOIP, with the higher temperature water providing only marginally improved recovery. Steamflooding at 550°F was shown to be capable of recovering more than 80% of OOIP and was much more efficient than the 330°F steamfloods. The lowest residual oil saturations and highest displacement efficiencies were consistently measured for rock type "C", a dirty Opal-A found in prior published research to be the most compressible of the various rock types.

Counter-current imbibition (CCI) of water and oil is considered to be a key mechanism in the published research performed to understand the effects of hot fluid injection in diatomite, where core samples were purposely tested at low effective stress levels to minimize the effects of compaction. Laboratory-measured displacement efficiencies are presented here for stress and temperature levels typical of field conditions, where the primary diatomite pore structure is radically altered and the diatomite skeletal material is crushed by thermally-induced compaction. Under these field conditions, displacement efficiencies are surprisingly high for hot fluid injection processes in diatomite, particularly for hot-water flooding. The remaining oil saturation data are applicable in numerical modeling studies, and differences in oil displacement efficiency by rock type highlight the need to use different geological facies when building geo-cellular models of diatomite reservoirs.
Low Salinity Oil Recovery–Increasing Understanding of the Underlying Mechanisms
Authors: Lee S. Y. , Webb K. J. , Collins I. R. , Lager A. , Clarke S. M. , O'Sullivan M. , Routh A. F. , Wang X.
Published: July 2010

Water injection has been used to increase oil recovery since the late 19th century. For over 100 years, the mechanisms behind this incremental oil recovery have been thought of as physical, i.e. the injection of water maintains reservoir pressure and sweeps the mobilised oil to the producing well. In the last decade this premise has been questioned and through the development of BP's LoSal™ EOR technology, it is now recognised that oil recovery through waterflooding also involves chemical processes and that modifying the brine chemistry of the injection water can significantly impact the observed recovery.

Several hypotheses regarding the mechanism involved with low salinity waterflooding have been discussed in the literature. In 2006, BP published a proposed mechanism for this phenomenon based upon multicomponent ion exchange (MIE) triggered by expansion of the electric double layer at the mineral surfaces that bind the oil.

This paper describes on going research studies focused on advancing the understanding of these mechanisms using sophisticated physical chemistry techniques such as Small Angle Scattering using neutrons from the ILL facility in Grenoble, France and the ISIS facility at the Rutherford Appleton laboratory, UK and X-rays at the DIAMOND Light source, Oxon. These techniques are capable of measuring the thickness of any water layer at the mineral surface down to the Angstrom level.

Results to date provide some support for the BP published mechanism. They have shown the presence of a thin water layer and its variation with changes in the salinity of the water medium at model silica and clay-like surfaces, with attached (model) polar oil components, suspended in oils. Furthermore, the impact of cation-type on the water-layer thickness has also been demonstrated.
Swelling/Extraction Test of a Small Sample Size for Phase Behavior Study
Authors: Tsau J. S. , Bui L. H. , Willhite G. P.
Published: July 2010

Swelling/extraction tests are single-contact phase-behavior experiments to measure the solubility of CO2 dissolved in crude oil and the amount of hydrocarbon that CO2 can extract or vaporize from crude oil. The tests are commonly conducted in a visual PVT cell with a large sample size (40–100cc). In this paper, an easy operated apparatus capable of determining phase behavior with a significantly smaller sample size (3 to 14 cc) is described. The apparatus consists of a high-pressure view cell, high-pressure and precision syringe pump filled with CO2, a water bath, and accessories to measure the temperature and pressure. The device is capable of determining vapor-liquid, liquid-liquid and vapor-liquid-liquid equilibrium commonly observed in a high pressure CO2 enhanced oil recovery process. The solubility of CO2 in oil, the expansion volume of oil due to the dissolution of CO2 as well as the phase transition during the test were quantified with excellent reproducibility. The molar volume of oil saturated with CO2 correlated linearly with the mole fraction of dissolved CO2 suggesting ideal mixing in the liquid phase. The phase behavior between CO2 and crude oil samples with different composition, temperature and pressure is discussed.
Numerical Coupling of Geomechanics and Fluid Flow During Steam Injection in SAGD
Authors: Zandi S. , Renard G. , Nauroy J. F. , Guy N. , Tijani M.
Published: July 2010

The Steam Assisted Gravity Drainage (SAGD) process is a thermal enhanced oil recovery (EOR) method that appears tremendously successful, especially for bitumen.

SAGD process results in a complex interaction of geomechanics and multiphase flow in cohesionless porous media. In this process, continuous steam injection changes reservoir pore pressure and temperature, which can increase or decrease the effective stress in the reservoir. Quantification of the state of deformation and stress in the reservoir is essential for the correct prediction of reservoir productivity, seal integrity, hydro fracturing and well failure. In SAGD process, the analysis of reservoir geomechanics is concerned with the simultaneous study of fluid flow and mechanical response of the reservoir.

The objective of this paper is to show the importance of taking into account the role of geomechanics in SAGD numerical modeling and to provide a better description of the rock contribution to fluid flow in the SAGD process. Therefore, we introduce a geomechanics-reservoir partially coupled approach, which allows a better predictive description of the SAGD process to be performed.

The results of numerical simulations show that the classical treatment of deformation of reservoir through the rock compressibility in the conventional reservoir theory is not a rigorous framework to represent the evolution of high porous rock strains that play a significant role in the performance of SAGD.
MEOR Success in Southern California
Authors: Zahner Bob , Sheehy Alan , Govreau Brad
Published: July 2010

A Microbial Enhanced Oil Recovery (MEOR) process was successfully applied to a mature waterflood in Southern California, using indigenous microbes that normally remain dormant during the producing life. Certain indigenous microbial species can be activated in waterflood reservoirs by introducing the correct blend of nutrients. Once activated, the microbes multiply when the nutrients deplete, then migrate to immobile oil in search of a food source. The microbes break up this residual oil saturation into smaller micro-droplets that can flow through pore throats and be swept to producers, yielding an increase in oil recovery. The application on a producing well led to an increase in well tests from 20 to over 80 BOPD. Following this encouraging test, the nutrients were applied in three batch treatments on each of the waterflood injectors. At peak response a thirty percent oil rate increase was seen in the offset producers. Because this process uses indigenous microbes, there are no compatibility issues with reservoir fluids or concerns about survival in a foreign environment. The results from this field application demonstrate that managing a reservoir's indigenous microbes can yield significant incremental oil production in a mature waterflood with a minimal investment.
Improved Oil Recovery using Thermally and Chemically Protected Compositions Based on co- and ter-polymers Containing Acrylamide
Authors: Gaillard N. , Giovannetti B. , Favero C.
Published: July 2010

The change in properties of several anionic polyacrylamides that were used in various EOR projects around the world is discussed. Due to mechanical, radical and/or thermal degradations reported, the molecular weight, anionicity and viscosity of polymer change from the time it is injected until breakthrough when it is produced. Strategies for optimizing the long term stability of EOR polymers have been developed for various polymer types combined with protective additives. Polymers investigated are acrylamide (AMD) based co- and ter-polymers functionalized with monomers such as sodium acrylate (AA), sodium acrylamido-tertiary-butyl sulfonate (ATBS) or N-vinyl pyrrolidone (NVP). The additives belong to five families: free radical absorber, oxygen scavenger, metal precipitant, chelating chemicals, and sacrificial agent. The additives have been selected in addition to their chemical properties for their physical and toxicological characteristics to allow to be formulated as one single formulation under the ready-to-use powder or inverse emulsion form. Chemical and thermal stability for polymer solutions containing 50 to 500 ppb of oxygen have been evaluated using a new test apparatus that allows precise control of the oxygen level. The "as is" stabilized polymer compositions can be used for polymer, surfactant polymer and alkaline surfactant polymer floods. With this technology, polymer viscosity is stable while it propagates through the reservoir and a favorable mobility ratio is maintained from injectors to producers. This enables better sweep efficiency and more efficient oil recovery. Laboratory data shows that new acrylamide based polymer compositions maintain viscosity in the presence of oxygen and iron at high temperature and salinity. ATBS, NVP containing polyacrylamides with protective additives are shown to have the best resistance to radical and thermal degradation. The viscosity of polymer solutions aged up to 120°C can typically reach 60 - 110 % of initial viscosity after a few months compared to 10-40% of previous systems. The polymer and additive combination must be optimized in order to achieve long term thermal and chemical stability at specific reservoir conditions. Results show that polymer flooding can be successful in reservoirs with relatively high temperature and poor water quality. Improved polymer compositions stability leads to increased oil recovery from chemical floods used in EOR.
In-Situ Phase Identification and Saturation Determination in Carbon Dioxide Flooding of Water Flooded Chalk Using X-Ray Computed Tomography
Authors: Niu Ben , Yan Wei , Shapiro Alexander A. , Stenby Erling H.
Published: July 2010

As an effective method to enhance oil recovery and to reduce green gas emission, injection of carbon dioxide (CO2) into water flooded petroleum reservoirs has obtained increasing attention. In the laboratory study of such a process, in-situ identification of different phases and determination of their saturations by use of X-ray computed tomography (CT) is the key to visualize flow and get insight into the mechanisms of the multiphase flows in porous media.

Although the flooding process is essentially three-phase, and involves interaction between oil, water and CO2 (mutual solubility, change of acidity, swelling of the oil etc.), there are few studies on identifying all the three phases and measuring their saturations, especially on chalk core under high pressure and temperature conditions. The purpose of our study is to experimentally identify different phases and to quantify their saturations during CO2 flooding. Laboratory experiments on injection of CO2 into chalk cores form the Danish North Sea, saturated with the doped live oil and the doped distilled water, have been carried out under high pressure and high temperature. Dopants were used to increase the accuracy in phase saturation determination, especially the in-situ CO2 saturation under three-phase flow conditions. The experiments utilized CT imaging to visualize the displacement patterns, in-situ fluid saturations dynamically during the flooding. Different image processing software have been used to ensure the validity of image analysis.

During the experiment, in-situ saturation of CO2 in the tertiary gas flooding has been determined quantitatively and the visualization of injection process was constructed dynamically. At the same time, production of various fluids was recorded dynamically during CO2 flooding, and based on those data, detailed analysis was conducted. The key factors and the preferential parameters needed for the successful application of the X-ray computed tomography to the multiphase flows in a chalk rock were also discussed.
Application of Internal Olefin Sulfonates and Other Surfactants to EOR. Part 1: Structure - Performance Relationships for Selection at Different Reservoir Conditions
Authors: Barnes Julian R. , Dirkzwager Henk , Smit Jasper R. , Smit Johan P. , On An , Navarrete Reinaldo C. , Ellison Bob H. , Buijse Marten A.
Published: July 2010

The development of structure – property relationships are described for new commercial grade internal olefin sulfonates (marketed as the ENORDET™ O series) and laboratory scale alcohol-alkoxy-sulfate surfactants for use in chemical flooding. Surfactant structure was characterised by an in-house developed liquid chromatography mass spectrometry (LC-MS) technique and properties focused on oil/water microemulsion phase behaviour. Such relationships are important to match the surfactant formulation to particular reservoir conditions (temperature, salinity and crude oil). The relationship between IOS structure (by LC-MS) and optimal salinity (by phase tests) has been modeled by the empirical HLB number and by a semi-empirical molecular model. An IOS 24-28 based surfactant system gave excellent microemulsion performance with several, regionally different crude oils and an initial correlation of performance with the composition crude oils has been made. The IOS surfactants described have been produced on a pilot scale and with consistent quality. This commercially available family, and the commercially available alcohol-alkoxy-sulfate family, cover most of the salinity and temperature reservoir conditions expected, though for high temperature and high salinity reservoirs, alcohol based sulfonates will most likely be required. Finally, the chemistry of production of the IOS surfactants and their handling properties are summarised. Part 2 of this paper (SPE-129769-PP) describes work to formulate an IOS mixture that was subsequently used in a successful ASP field test.
Application of Internal Olefin Sulfonates and Other Surfactants to EOR. Part 2: The Design and Execution of an ASP Field Test
Authors: Buijse Marten A. , Prelicz Ruth M. , Barnes Julian R. , Cosmo Claudio
Published: July 2010

This paper discusses the design and application of an alkaline-surfactant-polymer (ASP) system for the West Salym field in West Siberia. The discussion in the paper focuses on surfactant selection, and less on polymer selection. The optimum surfactant system for the West Salym crude is a combination of IOS 24-28 (internal olefin sulfonate with a tail length of 24-28 C-atoms) and IOS 15-18 and also includes an alcohol as co-solvent. The IOS surfactants are manufactured commercially by Shell Chemicals as the ENORDET™ O series. In an accompanying paper1 the properties of the IOS family of surfactants are discussed in more detail.

For optimum performance, the surfactant needs to be tailored to the crude oil. Although the oil is not too heavy (API density is 30), and has a near-zero TAN, it contains a significant fraction of heavier components such as asphaltenes and resins, which are surface active and can interfere with the surfactant in the oil-brine interfacial layer. It is discussed in the paper how the crude oil composition affects the surfactant selection process. From test results and theoretical considerations, it was concluded that these types of crude require a surfactant with a long alkyl tail, such as an IOS 24-28. Further optimisation of the surfactant formulation was based on phase behaviour, surfactant solubility and core flow tests. To adjust optimal salinity, and to improve solubilisation, a co-surfactant (IOS 15-18) and an alcohol (2-butanol) were also added.

Polymer tests were performed as part of the ASP design program. The purpose was to optimise the ASP/oil mobility ratio. Based on filtration and rheology tests, a hydrolysed poly-acrylamide polymer with a molecular weight in the range 5-8 million was selected.

The optimised ASP system was tested in the field in a single well chemical tracer (SWCT) test. The test design, execution and result will be discussed in the paper. The goal of the SWCT test was to measure -under field conditions- the ability of the ASP system to reduce the residual oil saturation. A tracer test was performed, to measure remaining oil saturation (ROS), before and after ASP injection. The test was executed successfully. Analysis of tracer response indicated that 90% of the ROS after waterflood was mobilized by the ASP flood.
Analytical Upgridding of Geocellular Model to Preserve Dynamic Flow Behavior in the Presence of Gravity Dominated Displacement
Authors: Rittirong Ake , Kelkar Mohan
Published: July 2010

In simulating enhanced oil recovery processes, it is critical that all the flow behaviors are properly accounted for in the simulation. Due to computation limitations, long calculation time, and complexity of physics, geological models cannot be directly used for field wide simulations. Upgridding reduces the number of grid blocks in the simulation model and hence make the simulation more efficient. An appropriate upgridding process needs to preserve the dynamic behavior of fine scale model.

We propose such a methodology. Previous methodologies were based on preservation of variability in the fine scale models. However, those methodologies do not necessarily account for the dynamic flow behavior. Instead, our new methodology is based on preserving the fractional flow character. In upgridding the fine scale model, we have developed a criterion by which the sequence in which the fine scale layers are combined is proposed such that fractional flow characteristics based on fine scale model are honored. Using this methodology, we can not only determine the sequence in which layers are combined, but also, to what extent we can upgrid the fine scale model.

The proposed methodology is developed for two-phase, two-dimensional flow under the effect of gravity segregated displacement. However, it is also tested for three-phase, three-dimensional flow in gravity dominated displacement with moderate effect of viscous and capillary forces. The proposed solution is analytical; therefore, computationally efficient. We have validated the methodology using both synthetic and field examples and demonstrate that the proposed methodology is superior to variance based methodologies.
The Study on Mechanism of Steel Pipeline Corrosion in Dagang Oilfield
Authors: Feng Qing-xian , Zhang Zhong-zhi , Shao Ding-bo , Ren Bao-sheng , Shi Ming-yi , He Feng
Published: July 2010

The differences of temperature and formation water characteristics among each reservoir were significant in Dagang oilfield. Although many measures have been taken in an attempt to control steel pipeline corrosion, the corrosion rate in the south block of oilfield was several times higher than that of the middle and north blocks. Further studies, therefore, were needed to clarify the case.

The ion and microorganism concentrations of the water in nine central stations were analyzed by sampling of aberration-free point. Under nonsterile and aseptic conditions, the relations among corrosion rate, salinity and SRB numbers were studied by static and dynamic methods. The results showed that, the salinity of formation water in the south block was the high (35g/L), and its SO42- content ranged from 50 to 150mg/L. In the south block of oilfield, the SRB number was less than 102cell/ml, but the corrosion rate was 71 percent higher than standard value. The case in the middle and north block of oilfield was inverse: the corrosion rate was 73 percent higher than that of the aseptic condition; production water was fit for microbial growth; the change law of pH and Eh was different. In the south block of oilfield, electrochemical corrosion was the main factor due to the higher salinity. In addition, microbiologically influenced corrosion was significant. The electron microscope analysis showed that, corrosion products were mainly iron and sulfur compounds, and calcium carbonate.

The influence of SRB on corrosion was obtained by experiment between SRB numbers and corrosion rates. A preliminary strategy was proposed to control and reduce SRB numbers, as well as to reduce corrosion.
A Proposed Pore-Scale Mechanism for How Low Salinity Waterflooding Works
Authors: Sorbie K. S. , Collins I. R.
Published: July 2010

In this paper, we propose a detailed, semi-quantitative, theory of how the low salinity waterflooding effect works based upon pore-scale theoretical considerations. This theory follows on from detailed core flooding work performed in our laboratories demonstrating the importance of multicomponent ion exchange (MIE) as the underlying mechanism of low salinity waterflooding (Lager et al, 2006). Whilst this earlier work highlighted the importance of MIE, it did not explain the precise consequences of the theory in terms of quantifying the incremental oil recovery nor the precise impact on pore-scale physics. For example, with MIE occurring, the changes in the divalent cation concentrations (Ca2+ and Mg2+) leads to the development of a "self freshening" zone within the waterflooded region within which certain changes in the surface chemistry of the pore walls may occur. Such effects include expansion of the electrical double layers, changes in the adsorption of polar organic species, and resulting changes in wetting. The theory presented here attempts to show the consequences of these changes which are supported by some plausible pore-scale model calculations. These calculations i) indicate the pore-scale origins of the low salinity oil recovery mechanism, ii) show the magnitude of the effect semi-quantitatively, and iii) allow some clear predictions to be made which can be tested experimentally. This work also follows Lager et al (2006) in further explaining why both crude oil and clay-bearing reservoir rock are required for the low salinity effect to occur, and why the effect is not seen in strongly water-wet, clay-free porous media with mineral oils. Thus, this proposed pore-scale physical model of the low salinity waterflooding effect both complements and extends previous mechanistic explanations based upon multicomponent ion exchange (MIE). Although this proposed mechanism is consistent with all the available observations, further experimental studies are required to definitively confirm it.
Application of Gas for Mobility Control in Chemical EOR in Problematic Carbonate Reservoirs
Authors: Srivastava Mayank , Nguyen Quoc P.
Published: July 2010

The use of gas for mobility control in chemical enhanced oil recovery is an attractive option to substitute polymer in conditions where its application is not feasible. Especially in carbonate reservoirs, which generally have low permeability and contains vugs and fractures, the use of polymer may result in the loss of permeability and benefits of chemical conformance control. In such conditions, gas is a good alternative. The direct dependence of dispersed gas mobility on rock permeability reduces the likelihood of gas plugging oil-rich low permeable rock matrix in carbonate reservoirs. The mobility of both gas and liquid phases in fractures can be controlled by changing fractional gas and liquid rates in such a manner that the two phases retains their flow characteristics.

A series of high performance surfactant-gas corefloods were performed on different core samples having very low to medium permeability values. In each experiment, foamed chemical slug was chased by foamed drive. The main objective of the research work was to determine mobility control characteristic of dispersed flow by evaluating pressure response and oil recovery data obtained from corefloods.

All corefloods resulted in oil recoveries above 75% of residual oil to waterflood. No early surfactant and gas breakthrough was observed, indicating absence of viscous fingering and presence of effective mobility control. The scaled pressure gradients remained within the practical limits observed in field EOR applications. Particularly, low pressure gradients observed at relatively high fluid rates indicates a degree of in-situ foaming for favorable injectivity, thus highlighting the potential use of gas in low permeability reservoirs. The beneficial effect of trapped surfactant mobilization on foaming, with the decrease in salinity, was observed in the form of increased foam strength during the drive injection phase.

The experimental study provides an insight into the effective application of gas in chemical floods in problematic carbonate formations. Substituting polymer with gas increases the applicability of chemical EOR methods in different types of reservoirs.
Water Shut-off with Polymer Gels in A High Temperature Horizontal Gas Well: A Success Story
Authors: Al-Muntasheri Ghaithan A. , Sierra Leopoldo , Garzon Francisco , Lynn Jack D. , Izquierdo Guillermo
Published: July 2010

A horizontal hot deep gas well was not on production due to high water cut. The well had a bottom hole temperature of 300°F (149°C) and a bottom hole pressure of 7,000 psi. The well was completed into a carbonate reservoir with an average permeability ranging from 2 to 3 mD. It was completed with a 7 in liner at a measured depth (MD) of 13,611 ft. The open-hole section extends from 13,611 to 16,456 ft. After the well completion operation, water was observed entering the open-hole section at the toe at a depth of 14, 677 ft. The exact water producing zone was identified by the resistivity log run on the subject well. Therefore, a mechanical packer was set in the open-hole section at 14,677 ft to isolate the water producing interval. The packer did not solve the problem. The water production continued to occur.

Due to their versatility, polymer gels were considered for remediating this problem and to revive the well. A gel system based on a low molecular weight polymer crosslinked with an organic crosslinker was considered. A serious challenge was the high temperature of the reservoir. The high temperature conditions imposed the use of a retarder to elongate the onset gelation time during the polymer gel placement. The available mixing waters in this field contained significant amounts of salts (a total dissolved solids content of 1,188 ppm). These solids caused compatibility problems upon contact with the commercially available retarder. Therefore, a new retarder was developed. The retarder was cost-effective, efficient and compatible with the available saline mixing water. The retarder's placement was examined in porous media under conditions similar to those encountered in the field (55 minutes placement time). The gel did not show any injectivity problems indicating the efficient nature of the retarder. The initial recommended recipe of the gel showed syneresis due to the extra amount of the crosslinker suggested. This was addressed by reducing the crosslinker concentrations in the gel recipe.

The treatment utilized a pre-flush to displace the reservoir fluids around the wellbore and to cool down the near wellbore area. This helped reduce the near wellbore area temperature from 300 to 240°F according to the temperature simulations. The gelant contained 250 gal/1000 gal of polymer with a 10 gal/1000 gal of crosslinker. After the gelant placement, the well was shut-in for three days. Once opened, the well showed an increase in gas production by a factor of 7.7 with a water cut reduction of 42 %.
Effects of Magnetic Field on the Motion of Multiphase Fluids Containing Paramagnetic Particles in Porous Media
Authors: Prodanovic Maša , Ryoo Seungyup , Rahmani Amir R. , Kuranov Roman , Kotsmar Csaba , Milner Thomas E. , Johnston Keith P. , Bryant Steven L. , Huh Chun
Published: July 2010

When paramagnetic nanoparticles are adsorbed at the oil-water interface or dispersed in one of the fluid phases in reservoir rock pores, then exposed to an external magnetic field, the resultant particle movements displace the interface. Interfacial tension acts as a restoring force, leading to interfacial fluctuation and a pressure (sound) wave. Here we focus on the interface motion. We apply the theory of ferrofluids to the case of an interface in a cylindrical pore. The predictions are consistent with experiments with an aqueous suspension of iron oxide nanorods in which the interface motion is measured by optical coherence tomography. The relative densities of the fluid phases (air/aqueous and dodecane/aqueous in our case) strongly affect the displacement of the interface. Application of a magnetic field introduces pressure-like terms into the equation of fluid phase motion. We then recast the problem in terms of interface motion, extending a numerical interface-tracking model based on the level-set method to account for capillarity and magnetic pressures simultaneously. We use the model to illustrate the motion of an interface between inviscid fluids at the pore scale when magnetic forces are imposed on one fluid phase.
Innovative Emergency Coiled-Tubing Disconnect System for Tender Barge Operations
Authors: Noguera J. A. , Hampson R. , Tran Q-B.
Published: July 2010

In the last few years, Indonesia has experienced a significant increase in offshore activities requiring support from tender barges. This type of operation has helped overcome most of the offshore well-intervention challenges, in terms of crane capabilities, space, load, etc. However, operating in high waves and strong currents has introduced other technical and safety challenges, especially when performing coiled-tubing (CT) operations.

In this kind of operation, the coiled-tubing reel and pumping spread are kept on the tender barge, while the injector head and well-control stack are set on the platform. The possibilities of losing the barge anchors or a catastrophic situation at the platform generated the need to develop a system to quickly disconnect the equipment on the barge from the platform by safely cutting the coiled tubing at the reel while minimizing the personnel exposure time to at-risk conditions, as well as avoiding the loss of treatment or hydraulic fluid to the environment. The new system was designed to be hydraulically capable of (1) releasing the injector and blowout-preventer (BOP) hoses while containing the hydraulic fluid, (2) holding the string reel end in place, and (3) cutting the string at the reel.

This paper will document the system components’ design processes, field testing, and field implementation.
Compositional Simulation of In-Situ Combustion EOR: A Study of Process Characteristics
Authors: Jain Priyanka , Stenby Erling H. , von Solms Nicolas
Published: July 2010

In order to facilitate the study of the influence of reservoir process characteristics in In-Situ combustion modeling and advance the work of Kristensen et al. in the domain of thermal oil recovery methods; a fully compositional In-situ combustion (ISC) model of Virtual Kinetic Cell (VKC; single-cell model) for laboratory scale combustion simulation is used. Preceding research work primarily focused on a kinetic model that was based on six components and incorporated four chemical reactions. However, modeling of a thermal process as complex as In-situ combustion requires in-depth understanding of detailed reaction kinetics and multidisciplinary process data. This paper extends the understanding of previous research done in this domain by performing the process simulations to study further the impact of oxidation reactions and combustion reactions of crude oils along with their saturate, aromatic, resin, and asphaltene (SARA) fractions. This incorporates fourteen pseudo components and fourteen reactions (distributed amongst thermal cracking, low temperature oxidation and high temperature oxidation). The paper presents a set of derivative plots indicating that reservoir process characterization, in terms of thermal behavior of oil, can be well construed by thermo-oxidative sensitivity analysis of SARA fractions. It can be interpreted from the results that operating parameters like air injection rate, oxygen feed concentration and activation energy have significant influence on oil recovery; an increase in air injection rate can lead to cooling of the combustion front and thus decrease oil recovery, while increase in oxygen feed assists combustion and contributes towards improved oil recovery. The critical properties of the pseudo components are not determined experimentally, thus extending significance to fluid characterization. The composition plays a key role e.g. due to asphaltenes being most resistant toward oxidation and saturates being the easiest oxidizable ones.
Snorre Low Salinity Water Injection - Core Flooding Experiments and Single Well Field Pilot
Authors: Skrettingland K. , Holt T. , Tweheyo M. T. , Skjevrak I.
Published: July 2010

Low salinity water (lowsal) flooding has been evaluated for increased oil recovery at the Snorre field. Core flooding experiments and a single well chemical tracer test (SWCTT) field pilot have been performed to measure the remaining oil saturation after sea water and after lowsal flooding.

The laboratory core flooding experiments done at reservoir and low pressure conditions involved core material from the Upper and Lower Statfjord and Lunde formations. The core material from the Statfjord formations gave incremental recovery in the order of 2 % of original oil in place (OOIP) by injection of diluted sea water. Similar amounts were produced during following NaCl-based lowsal injections. The same trend was observed in the high and low pressure experiments. No significant response to lowsal flooding was observed for Lunde cores. No response was normally observed during alkaline injection.

The SWCTT field pilot test was carried out in the Upper Statfjord formation. The average oil saturations after sea water injection, after lowsal injection and after a new sea water injection were determined; showing no significant change in the remaining oil saturation. The measured in-situ value of remaining oil saturation after sea water flooding was in agreement with previous SCAL experiments.

The measured effect of tertiary lowsal flooding from core experiments was in agreement with the SWCTT. Both measurements indicated only low or no effect from lowsal injection.

It has been suggested that lowsal flooding has a potential for improved oil recovery in all clayey sandstone formations containing crude oil. The results from this work indicate that the initial wetting condition is a crucial property for the effect of lowsal injection.
Chemical Degradation of Polyacrylamide Polymers Under Alkaline Conditions
Authors: Levitt David B. , Pope Gary A. , Jouenne Stephane
Published: July 2010

Hydrolysis of polyacrylamide-based polymers is rapid and extensive under the alkaline conditions typical of alkaline-surfactant-polymer (ASP) flooding. Even at room temperature, significant hydrolysis occurs within one to two months in the presence of sodium carbonate. While this implies that polymers used in ASP floods will rapidly become susceptible to precipitation with divalent cations, in most cases the alkali present will be the most sensitive component to precipitation so this may be a moot point. Also, autoretarding kinetics under alkaline conditions limit hydrolysis at 100 °C whereas complete hydrolysis occurs under neutral conditions. Furthermore, in-situ hydrolysis of initially unhydrolyzed polyacrylamide is proposed as a promising strategy for ASP floods since the injectivity of the unhyrolyzed polyacrylamide will be greater than hydrolyzed polyacrylamide due to its lower initial viscosity. The lower initial viscosity is not a disadvantage since once it has been hydrolyzed in-situ, its viscosity will increase.
Nanoparticle-Stabilized Emulsions for Applications in Enhanced Oil Recovery
Authors: Zhang Tiantian , Davidson Andrew , Bryant Steven L. , Huh Chun
Published: July 2010

Nanoparticle-stabilized emulsions have attracted many researchers' attention in recent years due to many of their specific characteristics and advantages over conventional emulsions stabilized by surfactants or by colloidal particles. For example, the solid nanoparticles can be irreversibly attached to the oil-water interface and form a rigid nanoparticle monolayer on the droplet surfaces, which induce highly stable emulsions. Those emulsions can withstand harsh conditions. Compared to colloidal particles, nanoparticles are one hundred times smaller, and emulsions stabilized by them can travel a long distance in reservoirs without much retention.

Oil-in-water and water-in-oil emulsions that are stabilized with different surface-coated silica nanoparticles of uniform size have been developed; these emulsions remain stable for several months without coalescence. The wettability of the nanoparticle determines the type of emulsion formed. The phase behavior with respect to the initial water/oil volume ratio (IVR), salinity, nanoparticle concentration and nanoparticle wettability was systematically examined. The emulsions were also characterized by measuring their droplet size and their apparent viscosity. Employing the hard-sphere liquid theory for nano-scale dispersions, the correlation between droplet/droplet interaction forces and droplet/droplet equilibrium separation distances has also been examined.
The Effect of Redox Potential and Metal Solubility on Oxidative Polymer Degradation
Authors: Levitt David B. , Slaughter Will , Pope Gary A. , Jouenne Stephane
Published: July 2010

Oxidative degradation of polymers is a serious concern in the field application of enhanced oil recovery polymers. This study is an attempt to resolve some of the discrepancies in the literature regarding the occurance and extent of this degradation, as well as to present a coherent framework for discussing the multitude of possible radical reactions. Sodium carbonate and bicarbonate are demonstrated to play a key role in stabilizing polymer against multiple reported sources of degradation, and it seems likely that this is due to their effect on iron solubility. Brines containing iron in the reduced state are often obtained from aquifers for use in polymer hydration. These brines are shown to be prone to causing immediate degradation if exposed to air during or after polymer hydration due to the oxidation of the iron. If this cannot be avoided, preaeration may be a feasible strategy to minimize degradation during hydration. However, care must be taken to ensure subsequent degradation is not caused by the injection of a polymer solution containing oxygen into a formation containing iron. For instance, sodium dithionite can be added downstream of the last exposure to oxygen. The use of sodium carbonate may also mitigate degradation due to the oxidation of iron (II) during polymer hydration.
Evaluation and Manufacturing Quality Control of Chemicals for Surfactant Flooding
Authors: Zhao Ping , Howes A. J. , Dwarakanath Varadarajan , Thach Sophany , Malik Taimur , Jackson Adam , Karazincir Oya , Campbell Curt , Waite Jeff
Published: July 2010

The success of chemical flooding rests heavily on the ability to deliver high-quality and repeatable surfactant in the field. While high-quality surfactants can easily be produced at lab scale, high oil recovery can be achieved only if similar quality product is produced at field scale. Scale-up of chemical production from batch-scale laboratory processes to field-scale continuous production requires a comprehensive program to evaluate surfactants produced at the bench-, pilot-plant and commercial scale to establish surfactant performance. Given the difference between batch-scale and continuous processes, small differences in surfactant structure can result thereby inducing differences in phase behavior and consequently oil recovery. Rigorous laboratory work is therefore required to synthesize and characterize surfactant samples in order to understand the correlation between structures/composition and performance in oil recovery. Following laboratory synthesis, pilot-plant studies are used to investigate process variables in order to understand their viability range and their impact on the large-scale product. Other important concerns are: optimal operational conditions, process repeatability, supply chain management, logistics, quality assurance/quality control, feedstock availability and dedicated procurement team. We present a case study for a proposed light oil surfactant polymer flood where a rigorous path for scale-up of surfactants from lab to pilot and finally field scale was evaluated via phase behavior experiments and coreflood testing. We show that phase behavior results are well correlated with coreflood recovery. For EOR, they are superior performance criteria to traditional specifications of physical and compositional properties for quality control. For the two-surfactant system presented herein, 272 surfactant samples, 512 formulations and 20 corefloods were conducted. The results from this large effort were utilized to develop appropriate manufacturing and quality-control processes to ensure the delivery of high-performance surfactants for field application.