Study on microwave-assisted synthesis of smart responsive magnetic Janus nanocatalysts for enhanced recovery of extra-heavy oil.

Reservoirs of high viscosity and low permeability are abundant and widely distributed in various countries, which can contribute an important percentage of oil output in the world. Conventional chemical flooding are suitable for low viscosity oil (less than 30 mPa·s) and medium/high permeability reservoirs (more than 50mD). However, it is a great challenge to applied chemical flooding technology for higher viscosity (30-500mPa·s) oil and lower permeability (1-50mD) reservoirs. On the one hand, the high contents of resin and asphaltene, or the formation of wax crystals in low reservoir temperature, lead to high oil viscosity and low oil recovery; On the other hand, low permeability can cause injection difficulty, and conventional chemical agents (polymers and formulations of chemical combination flooding) are difficult to inject. At present, the main exploitation mode is water flooding. However, because of high oil viscosity and low oil fluidity, the water flooding recovery is only about 15%. So it is very necessary to develop effective development technology. It is a good choice to develop water flooding with the intelligent viscosity reducer to decrease oil viscosity and improve oil fluidity, which has small molecular weight and can inject low permeability reservoirs easily. The performances of the viscosity reducer were studied in detail, including viscosity reduction efficiency, tripping oil film capacity, interfacial property, oil-displacement efficiency etc. The novel viscosity reducer with intellectual property show excellent properties. The viscosity reduction efficiency of the viscosity reducer was more than 80% (from 64.4 mPa·s to 10.3 mPa·s), and it could strip oil film within 40 seconds quickly, and could achieve ultra-low Interfacial Tension (IFT, less than 1.0×10-2mN/m).Alkali (NaOH or Na2CO3) could help to increase the viscosity reducing effects, and improve the stripping oil film capacity and interfacial property.The viscosity reducer had high oil-displacement efficiency; after water flooding, Oil recoveries increased 23% (OOIP, Original Oil In Place) with thehelp of this viscosity reducer.The novel viscosity reducer has viscoelasticity and shear-thinning ability. The monomer molecules can form the three-dimensional network structure in aqueous solution with high viscosity, which plays a role in enlarging the swept volume. With the increase of the shear rate, the three-dimensional network structure is broken down into the monomer molecules, and the viscosity decreases rapidly, so the viscosity reducer solution can inject low permeability reservoir easily.Compared with conventional polymer and polymer-surfactant, this viscosity reducer solution had better shear resistance and injectivity, and could filter membrane (0.2μm pore) effectively. The novel viscosity reducer can substitute for conventional polymer and polymer-surfactant in chemical flooding. This paper provides insights of a new effective EOR way for high viscosity and low permeability reservoirs.

The tertiary recovery of oil by chemical flooding is an admittedly complex process involving both micro and macroemulsions. The work reported here suggests from fundamental considerations of theory, operation and economics that in situ emulsification of the immobile residual oil (and mobile secondary oil) in the petroleum reservoir and its transport as such to the producing well is feasible and has many advantages over miscible processes. These include freedom from mobility control and ultralow interfacial tensions that call for substantial chemical outlays. Arguments are presented in support of this view with tertiary oil recovery data obtained from Berea core floods using cosurfactant-free aqueous solutions of two hydrocarbon sulfonates differing substantially in their solubility in water. A brief discussion of pertinent EOR methods is given, emphasizing the occasionally obscured but significant distinction, from an EOR-perspective, that exists between the mobile (secondary), and immobile (tertiary) components of the reservoir oil targetted by these processes.

Heterogeneities in the reservoir can result in poor sweep efficiency during water and chemical floods. In many cases the sweep efficiency is improved significantly when changing to polymer flood. However, in the presence of very high conductive features polymer by itself may not be sufficient and result in undesired polymer production. Diversion of the flow to oil saturated regions and minimization of polymer production is then desired. In the presence of cross-flow the best option is placing a (chemical) plug deep in the reservoir. Adding a second component to the injection polymer stream that can react with the polymer to form a cross-linked gel is then an effective solution. However controlled placement and triggering of the reaction is very challenging. In this paper we will present the results of static bulk measurements and dynamic core flooding experiments that were performed to identify cross-linked polymer systems. The polymers in the system are the typical high molecular weight partially hydrolyzed polyacrylamide (HPAM) polymers used in polymer flooding projects. The experimental work is focused on understanding and controlling the gelation time to enable proper placement and triggering at any given distance from the injectors. Parameters of investigation included temperature, brine composition, polymer concentration and rock mineralogy. The main parameters affecting the gelation process and possible failure mechanisms were identified. For given conditions, retardation of gelation time varying from few days up to several months could be designed. The learning from the experimental results can be used for improved material selection and design for other chemical and water flooding.

An important factor during the life of a heavy crude reservoir is the oil mobility. It depends on two factors, oil viscosity and oil relative permeability. Two characteristics of nanoparticles that make them attractive for assisting IOR and EOR processes are their size (1 to 100 nm) and ability to manipulate their behavior. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the surface of the particle, indicating an increasing in surface energy. Nanoparticles are also able to flow through typical reservoir pore spaces with sizes at or below 1 micron without the risk to block the pore space. Nanofluids or "smart fluids" can be designed by tuning nanoparticle properties, and are prepared by adding small concentrations of nanoparticles to a liquid phase in order to enhance or improve some of the fluid properties. However the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present the field evaluation of nanofluids for improving oil mobility and mitigate alteration of wettability in two Colombian heavy oil fields; Castilla and Chichimene. Asphaltenes sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil based nanofluid (OBN) containing these nanoparticles was evaluated as viscosity reducer under static conditions. Displacement tests through a porous media in core plugs from Castilla and Chichimene at reservoir conditions were also performed. OBN was evaluated to reduce oil viscosity varying oil temperature and water content. Maximum change in oil viscosity is achieved at 122°F and 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests, caused by the removal of asphaltenes from the aggregation system, reduction of oil viscosity, and the effective restoration of original core wettability. Two field trials were performed in Castilla (CNA and CNB wells), by forcing 200 bbl and 150 bbl of nanofluid respectively as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 270 bopd in CNA and 280 bopd in CNB and BSW reductions of ~11% were observed. In Chichimene also two trials were performed (CHA and CHB), by forcing 86 bbl of and 107 bbl of nanofluid as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 310 bopd in CHA and 87 bopd in CHB were achieved not BSW reduction has been observed yet. Interventions were performed few months ago and long term effects are still under evaluation. Results look promising making possible to think extending application of nanofluid in other wells in these fields.

2H-MoS ₂ Modified Nitrogen-Doped Hollow Mesoporous Carbon Spheres as the Efficient Catalytic Cathode Catalyst for Aprotic Lithium-Oxygen Batteries

This paper explains the importance for implementation of early water flood in near saturation pressure oil reservoirs particularly for the case having solution gas as dominant drive mechanism. The depletion in case of solution-gas drive (having no or minor support) with low to moderate in-place volumes is relatively fast. It is commonly observed that no pressure maintenance program is implemented till the reservoir pressure has been severely exhausted. This delay is generally caused by time consumed during understanding of fluid and reservoir behavior, and ultimately symbolizes the phrase ‘missing the train’. The objective of this study is to present the importance of early water flood and its impact on oil recoveries. A field was discovered in South Indus Basin which has half graben and four-way fault bounded structure with numerous splay faults. A well was drilled which encountered Sands ‘A’ and initially produced ~1360 bopd having ~4500 psia initial reservoir pressure. A detailed study was carried out when the reservoir pressure had depleted from 4500 to 1200 psia after draining ~400 MBO with ~1 Bscf associated gas. Based on the outcomes of the study, water flood was implemented by drilling an injector well ‘Inje-1’ which increased the pressure from 1200 psi to 4500 psi in the later life of field. Despite the pressure had rose to initial reservoir pressure, the recovery from the reservoir remained sub optimal. To understand the importance of implementing early water flood at higher pressures, a numerical simulation model was developed, history matched, and various sensitivities were run to see the impact of water flooding at various reservoir pressures during the life span of the field. It was observed that the recovery would have been more if the water flooding was implemented when the reservoir pressure was above bubble point. The reason being liberation of gas and shrinkage of oil resulting in high viscosity and low mobility oil remaining behind. If this liberation of gas is prevented by injecting water and conserving reservoir energy, both viscosity and mobility of oil would remain favorable due to delay in arriving at saturation conditions. Hence the recovery of these types of reservoirs can be enhanced by taking advantage of low viscosity and higher mobility of oil during early life. If the waterflood is implemented after exhausting the reservoir pressure, then the increased viscosity restricts oil flow and causes water channeling due to higher mobility contrast. As a result, leaving behind bypassed oil zones and very high residual oil saturation. In the present case study, it was observed that if the water flooding was implemented prior to reaching bubble point, recoveries would be 7-15% higher as compared to previous recovery. The early implementation would have added value to the overall project. Implementing the lesson learned, recent new discoveries are being evaluated to initiate water flood in early life. Early implementation of water flood in the oil reservoirs closed to saturation pressures will always be beneficial. Appropriate field development plan of the field and right decisions at right time will aid to enhance oil recovery. Once the energy in the oil reservoir is drained after producing gas, it is very difficult to regain the same energy.

Fracturing-flooding technology for low permeability reservoirs: A review

State of the Art of Western Canadian Heavy Oil Water Flood Technology K.A. Miller K.A. Miller Search for other works by this author on: This Site Google Scholar Paper presented at the Canadian International Petroleum Conference, Calgary, Alberta, June 2005. Paper Number: PETSOC-2005-251 https://doi.org/10.2118/2005-251 Published: June 07 2005 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Miller, K.A. "State of the Art of Western Canadian Heavy Oil Water Flood Technology." Paper presented at the Canadian International Petroleum Conference, Calgary, Alberta, June 2005. doi: https://doi.org/10.2118/2005-251 Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search nav search search input Search input auto suggest search filter All ContentAll ProceedingsPetroleum Society of CanadaPETSOC Canadian International Petroleum Conference Search Advanced Search AbstractHeavy oil water floods have been operated in Saskatchewan and Alberta for up to 50 years, yet remarkably little discussion of the theory or operation of heavy oil water flooding has been published.Conventional water flood theory is based on assumptions that are not met in heavy oil reservoirs, and those theoretical and operational experiences should not be substituted.This discussion uses information from the relatively small number of significant theoretical and field discussions of Western Canadian heavy oil water flooding available in the public domain to establish the 'state of the art,' including proposed production mechanisms, prediction of performance, and improvement of performance.IntroductionThe initial challenge to this study was deciding which water flooded pools to include under the 'heavy oil' umbrella. An imprecise definition of heavy oil is use by both government agencies and water flood operators. Definitions are often based on API gravity (a value of 蠄 20 ° API is sometimes used), but often the driving criterion is geography. If a water flood is located in an area near heavy oil cold production, it is sometimes simply classified as heavy oil, and given to the heavy oil group to operate.Emphasis on an oil-gravity-based definition of heavy oil is convenient, but unfortunate, as it de-emphasizes oil viscosity even though viscosity has repeatedly been shown to be a controlling parameter in numerical simulation runs. Aversion to a viscosity-based-definition for heavy oil may be due to occasional problems obtaining consistent heavy oil viscosity measurement1,2, and to confusion about whether available viscosity values were collecting using dead oil, live oil, or something in between. Despite this general neglect of viscosity data when discussing heavy oil water floods, the most cited statement about heavy oil water floods is "You can't have a successful heavy oil water flood if the dead oil viscosity is greater than" a particular value. 1,000 to 2,000 cp dead oil viscosity range (at reservoir temperature) is often cited as 'the limit,' but no study establishing this guideline could be located.Conventional water flood theory is based on assumptions regarding mobility ratio or fractional flow values that do not apply to heavy oil reservoirs, and should not be used to make project decisions. Even if 'heavy oil' is shown in the title of a water flood article, be aware that some conventional oil water flood technical staff consider oil with viscosity in the range of 3 to 10 cp, (much lower than the hundreds to thousands of cp oil more typically water flooded in Western Canada) to be heavy oil.There is a historic connection between conventional and heavy oil water flooding, and therefore an explanation for prior theory transfer, as early Western Canadian projects were likely initiated by those familiar with conventional water flooding to 'see what would happen.' Enough good things happened at selected projects for them to be continually expanded, and to sustain economic performance for up to 50 years and counting. Keywords: modeling & simulation, producer, production rate, heavy oil water flood, injection, viscosity, water flooding, water flood performance, water injection, water flood Subjects: Improved and Enhanced Recovery, Waterflooding This content is only available via PDF. 2005. Petroleum Society of Canada You can access this article if you purchase or spend a download.

A novel polycyclic aromatic hydrocarbon (PAH) based water-soluble viscosity reducer (VR) formulation was designed to reduce heavy oil viscosity for enhancing heavy oil production by chemical flooding. The polyaromatic structures such as benzene, naphthalene, and pyrene units in the VR formulation target asphaltene and resin components in heavy crude oil via π-π interaction to hinder formation and self-assembly of asphaltene aggregates and to reduce the viscosity of heavy oil accordingly. Two main chemical components in the VR package were synthesized from the reaction between poly(ethylene glycol) and naphthalenemethanol or pyrenemethanol to yield amphiphilic molecules. The chemical structured were confirmed by 1H NMR spectra. Heavy oil displacement evaluations were conducted through two experimental setups – a coreflooding equipment and a visualized micromodel. In the coreflooding experiments, a commercially available benchmark VR (BVR) and the synthesized VR (SVR) solutions at the optimized concentrations were injected to displace the heavy oil saturated in carbonate cores. The residual oil distribution pattern after injection of chemical slug and the profile change of saturated oil during chemical flooding with the BVR and SVR were observed using a micromodel equipment. At 0.2 wt%, the SVR package formed oil-in-water (O/W) emulsions with heavy oil at an oil-to-water ratio of 7:3 and dramatically reduced the viscosity of heavy oil by 84% at 50 °C. Visualized micromodel displacement tests showed that the injected SVR solution gradually emulsified the heavy oil at the oil/water interface to form emulsion droplets, which were subsequently deformed and stretched into long and narrow emulsion strips to pass through the smaller pores and throats along with injected fluid, thus facilitating the mobility of heavy oil and enhancing the oil production eventually. Coreflooding testing indicated that the injected SVR fluid significantly decreased the injection pressure due to viscosity reduction of the heavy oil. The oil production was enhanced by around 11% on the basis of water flooding. As a comparison, the heavy oil production by injection of the BVR solution was improved by 8%. The performance of the SVR on heavy oil viscosity reduction and oil displacement was found more pronounced than the BVR. Therefore, the formulated SVR package exhibits a great potential in heavy oil production.

Chemical combination flooding technology is one of the effective enhanced oil recovery (EOR) methods for high water cut sandstone reservoirs. Alkali-surfactant-polymer (ASP) flooding has been tested and applied in Daqing oilfield with significant EOR performance. When chemical combination flooding was extended to different reservoirs, one of key techniques is to develop chemical flooding formulations to fit the reservoir conditions. Huabei oilfield is a fault block reservoir with specific geological conditions and reservoir fluid properties other than Daqing oilfield. The average water cut was around 90% by water flooding. Chemical combination flooding is an alternative technique to enhance oil recovery. ASP and alkali-free surfactant-polymer (SP) combination flooding formulations were investigated for Huabei reservoir conditions based on polymers and surfactants screening tests, surfactant adsorption losses experiments and oil displacement core flooding experiments. The research results lay the foundation of pilot tests for chemical combination flooding applying to the fault block reservoir. Salt tolerant polymers including comb-shaped polymer KYPAM showed good viscosifying performances than conventional polymers when prepared with Huabei formation water. Petroleum sulfonates (PS) were selected for ASP and SP formulations. Ultralow interfacial tension between crude oil and ASP/SP solution prepared with formation water could be obtained at a widely range of surfactant concentrations from 0.05wt% to 0.3wt%. Adsorption losses of surfactants on core sand showed that the adsorption losses of surfactants were less than 1.00mg/g. Core flooding tests of chemical flooding proved that about 20%-23% incremental oil recovery over water flooding could be obtained by using ASP (1.0wt% Na2CO3 + 0.3wt% PS-1 + 1400mg/L KYPAM) or SP (0.3wt% PS-2 + 1200/1400mg/L KYPAM) flooding with an injection pore volume of chemical slug was 0.5PV. The experimental results were considered to be technical feasibility and effectiveness of chemical flooding EOR methods for the fault block reservoir, which might present further understanding for chemical EOR field application in Huabei fault block reservoirs.

Issran field is located 200 km east of Cairo-Egypt, producing from fractured dolomite reservoir 8-12 API oil gravity. The reservoir depth ranges from 1000-2000 ft, with BHP 300-500 psi and BHT of 120-200 F. The heavy oil viscosity is 4000 cp at standard conditions and the reservoir rock is oil wet with high H2S content. The high viscosity and low mobility of the Issran field heavy oil in contrast with the strong mobility and low viscosity of the formation water had extended the problem to a severe decline in hydro carbon production. In an attempt to enhance the production, Steam injection had been deployed in the field to reduce the oil viscosity and hence enhance the mobility of the extra heavy oil. Enhancement in production has dramatically increased after implementing a new technique combining the Steam Injection with the Matrix Stimulation Engineering Utilizing the Fiber Optics Telemetry Enabled Coiled Tubing. As the first time in the East Africa and East Mediterranean countries, the new technology deployed (Fiber Optics Telemetry Enabled Coiled Tubing) has provided a new dimension to the heavy oil thermal recovery by supplying a full Distributed Temperature Survey (DTS). Real time interpretation of the DTS data enabled the real time decision making during the Matrix stimulation treatment based on the actual downhole parameters. It also provided valuable data regarding mapping of the downhole steam injection utilizing coiled Tubing. This paper assesses the effect of using the new technology in Coiled Tubing services utilizing the DTS Measurements during Matrix Stimulation Treatment in different wells. It analyses the Successful production enhancement that provided a new dimension to the extra heavy oil enhanced recovery efficiency. It also quantifies the economical added value resulting from the usage of DTS data in respect to conventional matrix stimulation with conventional Coiled Tubing.

The volumetric sweep efficiency is an essential factor in the success of any water flooding or EOR project. Volumetric sweep efficiency (VSE) is controlled by the local reservoir geological settings, well patterns and completion design and production and injection strategies. In this paper we present a numerical modeling methodology to quantify VSE for different well patterns and geological settings independent of fluid types and saturation. The impact of conformance control techniques on VSE is estimated and the results translated to ultimate oil recovery for different driving mechanisms through standard analytical approximations. The methodology is used to evaluate the impact of conformance control techniques during water and polymer flooding for medium to high viscous oil reservoir. The results show that unselective blocking of high permeable layers during water flooding of high viscous oil reservoirs can be counterproductive and narrows the scope of potential chemical EOR opportunities. Polymer-(like) flooding wherever applicable is found to be in itself a very efficient conformance technique to increase the overall sweep efficiency for geological heterogeneities. In general abnormal high conductive features and long induced fractures tend to lower the efficiency of water or chemical flooding and cause excessive water/chemicals production to the surface facilities. Near wellbore mechanical treatments are then effective to minimize polymer production and increase oil production of which examples from ongoing polymer project will be discussed.

Crude oil production from conventional oil reservoirs is declining owing to heavy exploitation to meet the global energy market demand which is growing on a yearly basis. Unconventional oil resources, e.g. extra-heavy oil and bitumen, can compensate for this decline if appropriate enhanced oil recovery (EOR) methods are developed to enable economic flow from these resources. The main objective of this study is to set the best practice for the extra-heavy oil production of the Oykino-Altuninsky uplift of the Romashkinskoye oilfield (Tatarstan Republic, Russia). A series of experimental tests are applied on a real unextracted unconsolidated core sample from Romashkinskoye oilfield where the viscosity of the crude oil is above 600,000 cP at reservoir conditions. Different recovery schemes are tested experimentally and sequentially, namely: water flooding, hot water flooding, steam flooding, and finally in-situ combustion (ISC). Furthermore, the complete experimental run is simulated by a standard nonisothermal simulator and the results are compared to the experiments. On contrary to what was expected hot water at 100°C didn’t achieve any recovery from the sample and steam injection recovered only 11,5% of OOIP. ISC-is also known as fire flooding-attained the best recovery which reached 45% after steam flooding. Complete SARA analysis of the original oil and produced oil by steam and ISC is implemented to understand the mechanisms of each process. Numerical modeling is applied to the corresponding laboratory experiments and the results for water, hot water, and steam flooding were in good agreement with the experimental results while the in-situ combustion simulation showed a better recovery factor than experiments. The laboratory and numerical experiments will improve our understanding of the recovery options of Oykino-Altuninsky uplift of the Romashkinskoye oilfield and help the developers to choose the best production sequence for this oilfield particularly. Moreover, the experiments will provide inputs for the field-size numerical model after running more experiments on unconsolidated and consolidated cores.

The Faja Petrolifera del Orinoco (FPO), located in the southern part of the Eastern Basin of Venezuela, has the largest reserves of heavy and extra heavy oil in the world. These oils are highly viscous and their API gravities values are between 7 and 15, these properties together with the existence of multiphase flow make the production and transportation of these oil is highly complex. Therefore, it is necessary to use heavy oil transportation methods focused on reducing the viscosity of oil, this is achieved be removing or modifying the oil compounds that have been pointed out as the main cause of the high viscosity of these oils, such as: partial or total upgrading or slurry transportation. This study presents a flow modeling of a solid-liquid dispersion through horizontal pipes, which represents a slurry transportation, using a software of computational fluid dynamics (CFD) called FLUENT 6.3. For the simulation methodology was selected Euler-mixture in a three dimensional pipe model, with different concentrations of solids. The simulations were validated with experimental data development by PDVSA Intevep that contains pressure drops, temperature, solid characterizations and reological behavior of the slurry. The performance evaluation by the CFD model showed an acceptable fit when it is compared against experimental data, this results allow to understand the hydraulic behavior of heavy oil slurry transport through pipeline.

A laboratory quarter five-spot pattern chemical flood was conducted in a consolidated, homogeneous porous matrix for comparison with standard linear core floods. In addition to the routine material balance information, quantitative areal oil saturation isometric and contour plots were obtained from microwave attenuation measurements made during the flood. The microwave instrument provides the actual observation of oil banking and movement in a laboratory pattern chemical flood. Pattern flood oil banking characteristics are compared with those observed in linear floods. A volumetric linear scaling approach was used to predict the behavior of the pattern chemical flood from linear flood data. First, a stream tube model was assumed for the quarter five-spot flow pattern. The oil saturation distribution in each tube was computed from scaled linear core flood oil saturation distributions obtained by microwave attenuation. Details of this procedure are given. The comparison between predicted and observed pattern flood behavior is most encouraging. The average tertiary residual oil saturation and the tertiary oil breakthrough time were very accurately predicted. The observed tertiary Sor contours in the pattern flood did show slightly more cusping toward the producer than predicted by the simple model. An interpretation of the pattern flood response is proposed in terms of the scaling theory, its assumptions and its limitations.