Commercial Enhanced Oil Recovery Research Articles

Preparation and properties of nano-silica hybrid hydrophobic associated polyacrylamide for polymer flooding

Polymer flooding was one of the most commercial enhanced oil recovery (EOR) methods. It was the key to study novel polymer which had special properties for improving the oil displacement efficiency. In this study, a nano-hybrid polymer ([email protected]) for polymer flooding was synthesized by in situ polymerization with monomers and silica nanoparticles (SNP). The composition, micro-morphology and rheological properties of PAAM and [email protected] were characterized by FT-IR, 1H NMR, TEM, and rheometer. Compared with pure PAAM, the nano-hybrid polymers showed excellent viscoelastic, temperature resistance and shear resistance properties. The nano-hybrid polymer with the nanoparticle content of 1.5% w/w had the best performance. Improved performance of [email protected] could be attributed to the rigid SNP was dispersed into the polymer to interact with the polymer molecules, which enhanced the network structure of [email protected] and made the network structure of [email protected] more complex. [email protected] could make rocks tend to be water wet, which was good for oil displacement. In the enhanced oil recovery tests, nuclear magnetic resonance (NMR) visualization technology was combined with traditional core displacement experiments to study the effect of polymer flooding. The solution with a concentration of 0.1% w/w [email protected] increased oil recovery by 7.82% contrasting only 2.53% for the solution with a concentration of 0.15% w/w PAAM. Observation of cores during displacement by nuclear magnetic resonance imaging revealed that [email protected] reduced the mobility ratio oil to water and increased sweep efficiency notably. [email protected] had more obvious advantage in performance and more economical than PAAM, which made [email protected] have a better application in EOR.

A holistic approach to determine the enhanced oil recovery potential of hydroxyethylcellulose, tragacanth gum and carboxymethylcellulose

Several polymers have been investigated for their potential as an enhanced oil recovery process. In general, polymer dispersion in an injection fluid increases its sweep efficiency and mobility ratio leading to an increase in oil recovery rate. Though, harsh reservoir heterogeneous environment, lowers performance of different polymers under high formation salinity and temperature. Therefore, to achieve a profitable operational decision to recover crude oil, the oil and gas industry relies heavily on predicting various enhanced oil recovery (EOR) fluid performance in advance. Decisions on such recovery strategies should be taken at the lab scale before practical field job planning. In this study, we propose a holistic approach for analyzing and assessing tragacanth gum (TGU), hydroxyethylcellulose (HEC), and carboxymethyl cellulose (CMC) potential as an EOR fluid in three stages of screening methods, depending on the criteria that are well-established in the literature. We perform a comprehensive study based on the polymer rheological characteristics as first stage examination, wettability alteration features as second stage examination, and evaluation of additional oil recovery potential using oil reservoir simulating bioreactors (ORSBs) in the final stage. We integrate all the practical screening principles involving the reservoir characteristics through this innovative approach. The first stage screening showed better rheological characteristics of HEC and TGU, and the existence of wettability alteration capacities in these polymers was observed during the second stage screening. The final stage demonstrated that both these polymers (HEC – 7.38% and TGU – 6.71% of Residual Oil in Place) had higher additional oil recovery potential than polyacrylamide polymer (5.83%), a widely used commercial EOR polymer.

Enhancing Oil Recovery by Low Concentration of Alkylaryl Sulfonate Surfactant without Ultralow Interfacial Tension

AbstractSurfactant flooding plays a critical role in chemically enhanced oil recovery over the last half century, with the widely accepted mechanism of ultralow interfacial tension (IFT) by forming middle‐phase microemulsions with high concentration of a lead surfactant and a cosurfactant. However, it is found practically from field trials that high oil recovery efficiency can be obtained from low concentration surfactant flooding without forming microemulsions, and the principle behind has not been clearly unraveled yet. Here the solubilization of paraffin oil by the micelles formed with a commercial enhanced oil recovery surfactant, raw naphthenic arylsulfonates (NAS), was investigated using ultraviolet‐visible (UV–Vis) spectroscopy, dynamic light scattering (DLS), and transmission electron microscopy (TEM). It is found that paraffin oil can be well solubilized inside the NAS micelles, and mainly localized in the hydrophobic core of the micelles. The solubilization capacity of NAS micelles increases with increasing its concentration, and the size of micelles increases, but morphology of the micelles remains spherical with increasing the amount of paraffin oil, along with an appearance transition from transparent to opaque until the maximum solubilization capacity is reached. Core flooding results with crude oil indicate that in the presence of 0.24 wt.% polymer, addition of 0.1, 0.2, 0.5, and 1.0 wt.% NAS can get oil recovery factor of 24.1%, 27.0%, 30.5%, and 38.3%, which increases linearly with increasing NAS concentration though with the interfacial tension values only in the magnitude of 10−2 mN m−1 level. These findings prove preliminarily micellar solubilization can help increasing oil recovery efficiency even without ultralow IFT.

Enhancing oil recovery from high–temperature and high–salinity reservoirs with smart thermoviscosifying polymers: A laboratory study

While polymer flooding represents an effective chemically enhanced oil recovery (EOR) process, the poor thermal stability and weak salt tolerance of commonly used partially hydrolyzed polyacrylamide (HPAM) hindered such a technique to be used in high–temperature and high–salinity (HTHS) oil reservoirs. Here we examined the possibility to use two newly–developed smart thermoviscosifying polymers (TVPs), SAV–A and SAV–T, in comparison with currently used commercial EOR polymer, PT2500, in three types of simulated hostile oil reservoirs: 85 °C, 29,000 mg·L−1 NaCl, 1,000 mg·L−1 Ca2++Mg2+; 105 °C, 190,020 mg·L−1 NaCl, 10,000 mg·L−1 Ca2++Mg2+; 120 °C, 190,020 mg·L−1 NaCl, 10,000 mg·L−1 Ca2++Mg2+. It was found that both two TVPs presented thermo– and salt–viscosifying response at polymer concentrations higher than 0.2 wt% upon heating from 20 to 80 °C, with growing salinity from 32,000 to 220,000 mg·L−1, while only thermothinning behavior was observed for PT2500 under identical conditions. TVPs behaved better thermal stability than PT2500 where SAV–A topped the list, and both TVPs showed smooth propagation in the porous media. Higher recovery efficiencies of TVPs could be obtained compared with PT2500, especially at 105 and 120 °C, TVPs got recovery factor of 13.06% and 13.04% with only 0.21 wt% and 0.34 wt% polymer concentration, while merely obtained 9.52% and 8.21% recovery factor from PT2500 at polymer concentration as high as 1.4 wt% and 1.65 wt%, respectively. These findings may offer an alternative for chemical EOR in HTHS hostile environment.

Validating compositional fluid flow simulations using 4D seismic interpretation and vice versa in the SECARB Early Test—A critical review

This paper discusses strengths and weaknesses of 4D seismic interpretation as a technique for monitoring carbon dioxide that was injected as part of a large scale test associated with commercial enhanced oil recovery (EOR) at Cranfield Field, Mississippi, USA. The goals of the monitoring effort are 1) to make measurements to verify that the CO2 is contained in the reservoir according to operational designs and model predictions, and 2) that if there are deviations, to provide data which can be used to update the earth models and determine if any mitigation is needed. The current work uses a compositional numerical simulation to model CO2 flow in the reservoir and compares the results with estimates of changes in seismic properties between a pre-injection and a survey after more than 2 million metric tons injected. The complicated physics of the problem in Cranfield field present challenges to seismic interpretations. Our results show partial agreement between the results of the numerical simulation and the seismic interpretations. Possible causes of discrepancies among the fluid flow model and multiple interpretations of the same seismic data sets performed with different work flows illuminates the types of uncertainties that should be considered to achieve the goals of monitoring.

Thermothickening and Salinity Tolerant Hydrophobically Modified Polyacrylamides for Polymer Flooding

Partially hydrolyzed polyacrylamide (HPAM) is by far the most used synthetic polymer in enhanced oil recovery (EOR) projects. Shortcomings of HPAM include a highly molecular weight (Mw) dependent viscosity yield and decreasing viscosifying ability with increasing salinity and temperature. For an economically viable project, this limits its use to reservoirs with low to moderate salinities and temperatures. In that respect, hydrophobically modified polyacrylamides (HMPAM) has been suggested as an alternative for applications at higher salinities and temperatures. While studies have compared the performance of modified versus unmodified commercial EOR polymers at different salinities and temperatures, and the structure–property relationship of monodisperse, low Mw HMPAM, published data on the simultaneous effect of polymer hydrophobicity, salinity, and temperature for commercial EOR polymers are limited. This study thus presents a comprehensive series of experiments to investigate the effect of polymer hydr...

Monitoring 3.2 Million Tonnes of CO2 at the Bell Creek Oil Field

A research-monitoring program is being conducted at the Bell Creek oil field by the Plains CO2 Reduction Partnership, led by the Energy & Environmental Research Center, to evaluate and demonstrate the cost-effectiveness of strategies for monitoring CO2 storage associated with a commercial enhanced oil recovery (EOR) project. The Bell Creek oil field, operated by Denbury Onshore LLC as a commercial EOR project, is an oil-bearing, Lower Cretaceous sandstone reservoir located in southeastern Montana, USA. CO2 injection for commercial EOR began in May 2013 and has resulted in over 3.2 million tonnes of associated CO2 storage as of July 2016.

Incidentally Speaking: A Systematic Assessment and Comparison of Incidental Storage of CO2 during EOR with other Near-term Storage Options

CO2-based enhanced oil recovery (EOR) operations result in the associated storage of injected CO2 in a geologic formation as an intrinsic by-product of the oil recovery operation. There are key factual, legal and/or regulatory differences between this “associated storage” of CO2 and the storage of CO2 that is not conducted in association with an EOR operation (here termed “non-associated” storage). Associated storage of CO2 during large scale commercial EOR operations has been ongoing for over 45 years. Total injections exceed 1,000 million metric tons. This associated storage differs significantly from non-associated storage. It takes place as an inherent part of oil and gas development and production and not as a separate activity. The balancing of fluid output with fluid input during CO2-EOR helps manage and control movement of the injected CO2 and also conduces to a more stable and engineered pressure and risk profile and allows for a smaller areal extent. Unlike non-associated storage in saline formations, associated storage during EOR is highly regulated as part of oil and gas operations and is also the subject of many existing industry standards. However, some aspects are not fully addressed by the existing framework, such as a process for providing the public with documented assurance of safe, long-term containment of the injected CO2 and the quantification and accounting of the net amount of anthropogenic CO2 so contained. New standards can usefully address these issues by standardizing documentation of the assurance of safe, long-term containment and the careful quantification of the associated storage of anthropogenic CO2.

Wellbore corrosion and failure assessment for CO2 EOR and storage: Two case studies in the Weyburn field

Many depleted oil and gas reservoirs are targets for CO2 enhanced oil recovery, resulting in CO2 storage as part of the commercial enhanced oil recovery process. These oil fields have legacy wellbores that may contain a leakage pathway. Corrosion or degradation can occur anywhere along the wellbore through or along the cement, casing, tubing, or plugs and is a challenging issue facing the oil and gas industry. Two case studies presented here evaluate legacy wells in the Weyburn oil field. One well has injected over 263 million cubic meters of CO2, and the second well has not been exposed to CO2. These case studies aim to help understand casing corrosion in CO2-rich environments.Both wellbores exhibited signs of corrosion, with corrosion ranging from small pits to complete penetration through the casing. Contributing factors to corrosion in these wells range from exposure to injected fluids, injected CO2, packer placements, formation fluid exposure, and the corrosive environment that is present in the perforated area of the well.

<i>Saccharomyces </i><i>cerevisiae</i> from Baker’s Yeast for Lower Oil Viscosity and Beneficial Metabolite to Improve Oil Recovery: An Overview

This article is an overview of microbial enhanced oil recovery (MEOR) and the potential of Saccharomyces Cerevisiae to be applied in MEOR. MEOR may have same mechanisms with commercial enhanced oil recovery (EOR) but it used biological approach in improving oil recovery. Saccharomyces Cerevisiae produced carbon dioxide and ethanol under anaerobic condition. The carbon dioxide and ethanol that produced by this microbe are two from the six main MEOR agents in improving oil recovery. This articles also discussed on previous MEOR pilot projects that were conducted in Argentina, China and Malaysia.

Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery

Summary A new class of surfactants has been developed and tested for chemical enhanced oil recovery (EOR) that shows excellent performance under harsh reservoir conditions. These novel Guerbet alkoxy carboxylate (GAC) surfactants fulfill this need by providing large, branched hydrophobes; flexibility in the number of alkoxylate groups; and stability in both alkaline and nonalkaline environments at temperatures up to at least 120°C. The new carboxylate surfactants were recently manufactured at a cost comparable to other commercial EOR surfactants by use of commercially available feedstocks. A formulation containing the combination of a carboxylate surfactant and a sulfonate cosurfactant resulted in a synergistic interaction that has the potential to reduce the total chemical cost further. One can obtain both ultralow interfacial tension (IFT) with the oils and a clear aqueous solution (even under harsh conditions such as high salinity, high hardness, and high temperature with or without alkali) with these new large-hydrophobe alkoxy carboxylate surfactants. Both sandstone and carbonate corefloods were conducted, with excellent results. Formulations were developed for both active oils (contains naturally occurring carboxylic acids) and inactive oils (oils that do not produce sufficient amounts of soap/carboxylic acid), with excellent results.

Characterization and time-lapse monitoring utilizing pulsed-neutron well logging: associated CO2 storage at a commercial CO2 EOR project

Abstract The Plains CO 2 Reduction (PCOR) Partnership, led by the Energy & Environmental Research Center (EERC), is working with Denbury Onshore LLC (Denbury) and Schlumberger Carbon Services to study monitoring, verification, and accounting (MVA) of CO 2 storage associated with a commercial enhanced oil recovery project at the Denbury-operated Bell Creek oil field located in southeastern Montana. MVA techniques such as time-lapse pulsed-neutron logs (PNLs) have helped to update the local stratigraphy, guide a repeat vertical seismic profile, monitor changes in oil and gas saturations near the wellbore, and further guide additional PNL monitor passes.

Overview of the Bell Creek Combined CO2 Storage and CO2 Enhanced Oil Recovery Project

The Plains CO2 Reduction (PCOR) Partnership, led by the Energy & Environmental Research Center, is working with Denbury Onshore LLC (Denbury) to characterize and monitor a large-scale CO2 enhanced oil recovery (EOR) and CO2 storage project at the Bell Creek oil field located in southeastern Montana, USA. Denbury owns and operates the field and will carry out the commercial EOR project. The PCOR Partnership is applying an integrated approach to site characterization, modeling, predictive simulation, risk assessment, and monitoring to improve understanding of the interrelationship between CO2 storage and EOR in a clastic reservoir.

Subsurface characterization and geological monitoring of the CO 2 injection operation at Weyburn, Saskatchewan, Canada

Abstract The IEA Weyburn Carbon Dioxide (CO 2 ) Monitoring and Storage Project analysed the effects of a miscible CO 2 flood into a Lower Carboniferous carbonate reservoir rock at an onshore Canadian oilfield. Anthropogenic CO 2 is being injected as part of a commercial enhanced oil recovery operation. Much of the research performed in Europe as part of an international monitoring project was aimed at analysing the long-term migration pathways of CO 2 and the effects of CO 2 on the hydrochemical and mineralogical properties of the reservoir rock. The pre-CO 2 injection hydrochemical, hydrogeological and petrographical conditions in the reservoir were investigated in order to recognize changes caused by the CO 2 flood and to assess the long-term fate of the injected CO 2 . The Lower Carboniferous (Mississippian) aquifer has a salinity gradient in the Weyburn area, where flows are oriented SW–NE. Hydrogeological modelling indicates that dissolved CO 2 would migrate from Weyburn in an ENE direction at a rate of about 0.2 m/annum under the influence of regional groundwater flow. Baseline gas fluxes and CO 2 concentrations in groundwater were also investigated. The gas dissolved in the reservoir waters allowed potential transport pathways to be identified. Analysis of reservoir fluids proved that dissolved CO 2 and methane (CH 4 ) increased significantly in the injection area between 2002 and 2003. Most of the injected CO 2 exists in a supercritical state, lesser amounts are trapped in solution and there is little apparent mineral trapping. The CO 2 has already reacted with the reservoir rock sufficiently to mask some of the strontium isotope signature caused by 40 years of water flooding. Experimental studies of CO 2 –porewater–rock interactions in the Midale Marly Unit indicated slight dissolution of carbonate and silicate minerals, followed by relatively rapid saturation with respect to carbonate minerals. Carbon dioxide flooding experiments on similar rock samples demonstrated that porosity and gas permeability increased significantly through dissolution of calcite and dolomite. Several microseismic events were recorded over a six-month period and these are provisionally interpreted as being related to small fractures formed by injection-driven fluid migration within the reservoir, as well as other oilfield operations. Experimental studies on the overlying and underlying units show similar reaction processes; however secondary gypsum precipitation was also observed. Reaction experiments were conducted with CO 2 and borehole cements. The size and tensile strength of the cement blocks were unaffected, however their densities increased. Pre- and post-injection soil gas survey data are consistent with a shallow biological origin for the measured CO 2 in soil gases. Isotopic (δ 13 C) data values are higher than in the injected CO 2 , and confirm this interpretation. No evidence for leakage of the injected CO 2 to ground level has been detected. The long-term safety and performance of CO 2 storage was assessed by the construction of a features, events and processes (FEP) database that provides a comprehensive knowledge base for the geological storage of CO 2 .