Enhanced Oil Recovery

Transport of emulsions in porous media is relevant to several subsurface applications. Many enhanced oil recovery (EOR) processes lead to emulsion formation and as a result conformance originating in the flow of a dispersed phase may arise. In some EOR processes, emulsion is injected directly as a mobility control agent. Modeling the flow of emulsion in porous media is extremely challenging due to the complex nature of the associated flows and numerous interfaces. The descriptions based on effective viscosity are not valid when the drop size is of the same order of magnitude as the pore-throat characteristic length scale. An accurate model of emulsion flow through porous media should describe this local change in mobility. The available filtration models do not take into account the variation of the straining and capturing rates with the local capillary number. In this work, we present experiments of emulsion flow through sandstone cores of different permeability and a first step on a capillary network model that uses experimentally determined pore-level constitutive relationships between flow rate and pressure drop in constricted capillaries to obtain representative macroscopic flow behavior emerging from microscopic emulsion flow at the pore level. A parametric analysis is conducted to study the effect of the permeability and dispersed phase droplet size on the flow response to emulsion flooding in porous media. The network model predictions qualitatively describe the oil-water emulsion flow behavior observed in the experiments.

The vision of the Gulf Coast Carbon Center is to seek to impact global levels of GHG in the atmosphere by doing science and engineering studies that will support reduction of CO2 emissions and enable the development of an economically viable, multifaceted, CO2 sequestration industry in the Gulf Coast. This industrial-academic consortium is investigating issues related to assessing the pathways that would make capture and pipeline transportation economically feasible and environmentally effective within a specific regional context. Key issues considered are capture in the context of the current market, pipeline infrastructure, the role of enhanced oil recovery, and permanence in a basin with many wells. .

The Vapor Extraction (VAPEX) process, a newly developed Enhanced Oil Recovery (EOR) process to recover heavy oil and bitumen, has been studied theoretically and experimentally and is found a promising EOR method for certain heavy oil reservoirs. In this work, a simulation study ...

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impac...

Sulfide accumulation due to bacterial sulfate reduction is responsible for a number of serious problems in the oil industry. Among the strategies to control the activity of sulfate -reducing bacteria ( SRB ) is the use of nitrate, which can exhibit a variety of effects. We investigated the relevance of this approach to souring oil fields in Oklahoma and Alberta in which water flooding is used to enhance oil recovery. SRB and nitrate -reducing bacteria ( NRB ) were enumerated in produced waters from both oil fields. In the Oklahoma field, the rates of sulfate reduction ranged from 0.05 to 0.16 M S day À 1 at the wellheads, and an order of magnitude higher at the oil -water separator. Sulfide production was greatest in the water storage tanks in the Alberta field. Microbial counts alone did not accurately reflect the potential for microbial activities. The majority of the sulfide production appeared to occur after the oil was pumped aboveground, rather than in the reservoir. Laborator...

The article deals with the mechanism
of permeability reduction and methods
of impact on the rock in the bottomhole
formation zone. The change in the properties
of the bottomhole formation zone during injection
and production is shown; an estimation
of the state of the bottomhole formation
zone and the choice of the impact method
are given. The analysis of the technology of
reagent processing of the bottomhole formation
zone is carried out. Acid treatment of
producing wells and acid treatment of injection
wells are described.

The Pelana Field is a mature waterflood field in the Central Sumatera Basin that consists of multi-layer sands with contrasted properties. Waterflood has been applied since 1997, targeting all producing reservoirs. These layering reservoirs are challenging in achieving a good alignment in term of waterflood optimization. In multi-layer injectors, such a condition will lead to bad vertical distribution of injection, where the poorest quality sand receives the least water injected.

This is a problem occurring in some injectors in the Pelana Field, where the injection is not evenly distributed vertically so that the topmost reservoir, which also has the poorest quality with permeability of around 100 mD, does not receive enough injection to balance its production. Most of the injected water goes to MN_XX sand which has permeability of about 1000 md. Injector PL-55, for instance, injects into both sands to support the production from both reservoirs. However, the previous completion uses only open ended tubing and therefore, based on the spinner result, the water will be distributed naturally based on the well-to-reservoir pressure difference, being directly affected by reservoir permeability. This practice resulted in an unbalanced performance for both sands. While MN_XX has a good sweep efficiency with recovery factor (RF) increment > 8%, the BK_AA sand would has an opportunity to be optimized due to its current low incremental of RF.

Side Pocket Mandrel has been chosen to resolve the vertical distribution problem in PL-55 and improve the injection rate into BK_AA sand. It is observed that the well can finally split its injection into more desirable allocation, allowing more water to flow into BK_AA sand. This paper presents the application of this technology in PL-55 well, including the technology principles, the tool design, the strategy to improve the injection distribution and the enhanced performance to the surrounding producers.

There are primary, secondary and improved recovery methods that are developed according to the Field's needs, however, the primary recovery does not influence the increase of reservoir´s energy as the secondary and improved recovery does. Mature fields require such an increase in energy due to their production time, so water, gas or chemical injection methods also known as enhanced recovery methods (EOR) are required to satisfy the hydrocarbon demand of the moment.
This project search to quantitatively evaluate the implementation of a new enhanced recovery technology, such as the injection of silica nanoparticles, comparing it with conventional chemical recovery methods (Surfactant and Polymer) and thus determine its effectiveness and viability in the model sector of Yariguí-Cantagallo Field.

In this work, the performance of three natural surfactants (one produced by a bacteria and two of vegetal origin) in comparison to synthetics surfactants (cationic, anionic, non-ionic and zwitterionic) for its potential use in enhanced oil recovery EOR application was compared. The basis of comparison was basically the surfactant's solutions surface tension (ST) at room temperature, in the presence and absence of brine (salinity of about 4.7%). These measurements were developed to estimate if surfactants will resist reservoir conditions such as 75 °C and high salinities (up to 5%), conditions prevailing in the oil-field of Chicontepec, Veracruz (Mexico). Results of the work showed that biosurfactants could have potential for EOR process. The rhamnolipid produced by Pseudomonas and guar gum natural surfactants developed characteristics as good or even better than the synthetic surfactants normally employed in this process. The rhamnolipid produced by Pseudomonas seems to be a natural surfactant with extremely interesting characteristics. Rhamnolipid solutions yielded quite low ST at low concentrations (i.e. < 30 mN/m), even in the presence of brine for concentrations below 0.08%. Heat treatment applied to rhamnolipid solutions change very slightly the ST values when solutions contained no salts and about of 30% oil when brine was present. Rhamnolipid solutions did not show the higher foam capabilities, but represented half the capability of Polafix CAPB surfactant in producing foam. Neither guar nor locust bean gums showed important diminutions of ST at different concentrations in the solution. Nevertheless, for certain gum concentrations and in the presence of brine, guar gum had a very good performance (0.02%). Neither guar nor locust bean gums produced foam.► The Pseudomonas rhamnolipid is a natural surfactant with extremely interesting characteristics. ► For certain concentrations in the presence of brine, guar gum had a very good performance. ► Neither guar nor locust bean gums produced foam.

Chemical materials such as alkaline, surfactants, and polymers are widely used for the chemical EOR to reduce the trapped oil saturation in the reservoirs. Parameters such as surfactant adsorption and surfactant loss affect the performance of the mentioned EOR method. In this paper an attempt is made to enhance the performance of the surfactant flooding by application of nanoparticles. A series of core flooding tests were completed for sandstone core samples under reservoir conditions to study the effect of a novel application of nanoparticles to alter the properties of the surfactant in chemical flooding EOR processes. Sodium dodecyl sulfate (SDS) is widely used for the EOR approach. Silica nanoparticles were used to change the surfactant adsorption on the rock surfaces. The results showed that the addition of hydrophilic nanoparticles reduces the surfactant adsorption on the rock and improves the performance of the surfactant flooding which increases the oil recovery.

This study evaluates the potential of carbon dioxide-enhanced oil recovery (CO2-EOR) to reduce greenhouse gas emissions without compromising oil production goals. A novel, dynamic carbon lifecycle analysis (d-LCA) was developed and used to understand the evolution of the environmental impact (CO2 emissions) and mitigation (geologic CO2 storage) associated with an expanded carbon capture, utilization and storage (CCUS) system, from start to closure of operations. EOR operational performance was assessed through CO2 utilization rates, which relate usage of CO2 to oil production. Because field operational strategies have a significant impact on reservoir engineering parameters that affect both CO2 storage and oil production (e.g., sweep efficiency, flood conformance, fluid saturation distribution), we conducted a scenario analysis that assessed the operational and environmental performance of four common and novel CO2-EOR field
development strategies. Each scenario was evaluated with and without stacked saline carbon storage, an EOR/storage combination strategy where excess CO2 from the recycling facility is injected into an
underlying saline aquifer for long-term carbon storage. The dynamic interplay between operational and environmental performance formed the basis of our CCUS technology analysis. The results showed that all CO2-EOR evaluated scenarios start operating with a negative carbon footprint and, years into the project, transitioned into operating with a positive carbon footprint. The transition points were significantly different in each scenario. Water-alternating-gas (WAG) was identified as the CO2 injection strategy with the highest potential to co-optimize EOR and carbon storage goals. The results provide an understanding of the evolution of the system’s net carbon balance in all four field development strategies studied. The environmental performance can be significantly improved with stacked storage, where a negative carbon footprint can be maintained throughout the life of the operation in most of the injection scenarios modeled. This information will be useful to CO2-EOR operators seeking value in storing more CO2 through a carbon credit program (e.g., the 45Q carbon credit program in the USA). Most importantly, this study serves as confirmation that CO2-EOR can be operationally designed to both enhance oil production and reduce greenhouse gas emissions into the atmosphere.

The present study investigated the ability of a thermophilic anaerobic microbe (herein coded as AR80) for MEOR with the further objective to quantify the uncertainty of production forecast in terms of the cumulative probability distribution. A series of core flood experiments conducted in water-flooded Berea sandstone showed that up to 51% of initial oil-in-place was recovered when the plugs were treated with AR80 and shut-in for 14 days. Mainly, the oil recovery mechanisms were attributed to viscosity enhancement, wettability changes, permeability and flow effects. Matching the laboratory data using artificial intelligence: the optimized cumulative oil recovery could be achieved at an enthalpy of 894.2 J/gmol, Arrhenius frequency of 8.3, residual oil saturation of 20%, log of capillary number at microbe flooding stage of −1.26, and also depicted a history match error less than 3%. Therefrom, a sensitivity analysis conducted on reservoir shut-in period effect on oil recovery revealed that a relatively shorter shut-in period is recommended to warrant early incremental oil recovery effect for economical purposes. In addition, MEOR could enhance the oil recovery significantly if a larger capillary number (between 10−5 and 10−3.5) is attained. Per probabilistic estimation, MEOR could sustain already water-flooded well for a set period of time. This study showed that there is a 20% frequency of increasing the oil recovery by above 20% when a mature water-flooded reservoir is further flooded with AR80 for 2 additional years. Lastly, it was demonstrated herein that increasing the nutrient (yeast extract) concentration (from 0.1 to 1% weight) had less or no significant effect on the oil viscosity and subsequent recovery.

Nowadays, due to the remarkable oil reduction in oil fields, enhanced oil recovery (EOR) techniques have been considered by a large number of scientists and company. Situ oil extraction is normally done by these techniques with high efficiency. In this particular study, five different surface active agents (surfactant), two kinds of oil with various API, two kinds of sulfonated polyacry-lamide, two different electrolyte solutions with various TDS and two distinctive alcohols were tested and evaluated. An optimal formulation in terms of the properties and quantity of materials has to be used in order to enhance oil recovery, achieved by investigation of surface tension and the phase behavior of mentioned substances. Rheological behavior of polymer flooding and surfactant was studied. Employing this formulation, the maximum micro emulsion of oil in water occurred. Due to the synergy between surfactant and alcohol (as a co-surfactant), relatively lower amounts of sur-factants were used which led to the dip in the cost of operation, and ultimately the efficiency of operation improved.

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Surfactants have all along been used to reduce the interfacial tension (IFT) between oil and water to overcome the trapping phenomena that causes about 65% of the crude oil to be trapped after the primary and secondary recovery. The costs of surfactants on the other hand derived from petroleum-based source are costly. In this study, lignin was extracted from black liquor obtained by pulping local oil palm and coconut fiber and mixing it with amine and Sodium Dodecyl Sulfate (SDS) to form surfactant formulation for application in surfactant flooding experiments. Three formulations from each lignin with lowest IFT were evaluated for their performance in remobilizing residual oil recovery through oil displacement experiments using glass bead packed model at room temperature.  For the formulation containing oil palm lignin, the forth formulation (SDBS-E4) gives the highest oil recovery (4.10 % of original oil in place) and the formulation from coconut fiber, the fifth formulation (SDBS-C5) gives the second highest oil recovery (3.30 % of original oil in place). The results show that lignin based surfactants have a good potential to recover oil.
Key words: Black liquor, oil palm, coconut fiber, lignin, surfactant, enhanced oil recovery

Nigeria is gradually advancing into the secondary stage of oil recovery, necessitating preparation for tertiary oil recovery especially enhanced oil recovery (EOR). Considering the high cost of EOR agents, it is imperative to investigate the performance of available local EOR agents against foreign agents when these agents (such as surfactants and polymers) are used in combination. Oil displacement experiments were thus conducted using foreign and local surfactant-polymer (SP) and alkaline-polymer (AP) agents on Nigerian crude and their results were compared. The experiments entailed using different percentage ratios of surfactants to polymers and alkaline to polymer. Four kinds of Alkaline were also used to displace residual oil from sand to find out what type of alkaline displaces oil better. The displacement efficiencies obtained from experimental results showed that the foreign EOR agents performed better than the local EOR agents. For the SP agents, the foreign SP displaced above 90% of both light and medium crude at about 45/55 percentage and 0/100 percentage respectively. The local SP displaced a maximum of about 35% of the light crude and 75% of medium crude at an SP ratio of about 20/80 for both cases. The use of Alkaline-Polymer results showed that the foreign agents performed better than the local agents. The maximum displacement efficiency of the foreign AP was 78.13% at a ratio of 40/60 while the maximum displacement efficiency of the local AP was 64% at a ratio of 60/40. The displacement of residual oil experiments performed using four kinds of alkaline showed that potassium hydroxide (KOH) enhances recovery better than NaOH, Na 2 CO 3 and Palm bunch ash (a local source of alkaline). It was also observed that oil displacement efficiency increased as pH value of the alkaline increased.

In Ecuador, the fields are getting more challenging in terms of reservoir depletion. Inchi field is an example of such a field in which the production is normally obtained using electric submersible pumps (ESP), with a fast production decline. The wells start with production rates of 1,000 BOPD, and immediately production and pump intake pressure begin to decrease, thus requiring a secondary recovery technique such as water injection. However, the water to inject at required pressure is not always available, andspecial facilities are required to execute this operation, which increasescapital expenditures (CAPEX). Using a new approach that used the advantages of ESP sensors and operational flexibility, a production well was selected and converted to an injection well thus avoiding the high investments in surface facilities and making the secondary recovery a feasible option for low-producing wells. The Inchi A8 well on the Inchi A pad, was converted toa production injection well due to lack of available water in the field and production facilities. The paper includes an analysis of the completion design, ESP design, sensor installation modification for real-time injection pressure monitoring, ESP performance, injection stimulation, and results with the performance analysis for production recovery of nearby wells. The experience shared in this paper will let the reader understand the challenges for installation of a production injection well driven by the specific needs for and the advantages of injection pressure monitoring. After the installation of the production injection completion, the decrease in production and reservoir pressure stopped, the production in the field increased up to 166 BFPD in the Inchi 01 and Inchi A5 wells, the flowing bottomhole pressure has increased inan average of 100 psi in the wells Inchi 01 and Inchi A5, and in the well Inchi B6 the flowing bottomhole pressure is steady now closed to 600 psi (before was constantly decreasing). The injection pressure monitoring has been useful especially during the injection pressure tests performed by a testing unit, which allows to check the actual injection index of the reservoir. The savings associated with the installation of the production injection well include eliminating the need for additional surface facilities, a pipeline to bring water from the main station, and the construction of the water treatment plant in the location.

Surfactants have already been distinguished as having commercial application in oil industry especially Enhanced Oil Recovery (EOR) processes. During EOR processes, surfactants or a mixture of surfactants and polymers are injected into the reservoir to reduce the interfacial tension of microemulsion typically from about 30 dyn/cm to 10 −3 dyn/cm. Polymers are added to reduce the mobility by increasing the viscosity of the solution. The geometrical micelle shape of a number of surfactants might change from spherical to cylindrical above a concentration generally known as critical micelle concentration. Although previous studies haven't considered the effect of surfactants on solution viscosity, this shape transition could significantly affect the viscosity of solution. In this study, a previously developed model is used in conjunction with experimental data to investigate the effect of surfactant and salt concentrations on the micelle shape transition. It is found that for some ranges of surfactant and salt concentrations; shape transition from spherical to cylindrical causes a considerable increase in the viscosity of dodecyl ammonium chloride (DeAC) solution. Based on the results of this study, a number of surfactants could be used for simultaneous modification of the IFT and viscosity of the microemulsion rather than using both polymers and surfactant.

An overview of the enormous potential for increasing oil production in Trinidad's oilfields which are mostly depleted. Currently percentage of OOIP is only 25% or so and a further 3.5 million barrels are recoverable using CO2 and other EOR methods

Chemical flooding has been found to be one of the major EOR
techniques especially for reservoirs where thermal methods are not feasible.
The application of chemical flooding is strongly influenced by the current
economics, type of reserve oil and crude oil price. In this paper, an up to
date status of chemical flooding at the laboratory scale, pilot projects and
field applications have been reported. The basic mechanisms of different
chemical methods have been discussed including the interactions of
different chemicals with the reservoir rocks and fluids. The average recovery of
oil after the conventional water flooding is highly encouraging particularly
when the demand and price of crude oil is increasing day by day.