Shubham, Agrawal (Texas A&M University at Qatar) | Martavaltzi, Christina (Texas A&M University at Qatar) | Dakik, Ahmad Rafic (Texas A&M University at Qatar) | Gupta, Anuj (Texas A&M University at Qatar)
It is well known that the majority of carbonate reservoirs are neutral to oil-wet. This leads to much lower oil recovery during waterflooding since there is no spontaneous imbibition of water in heterogeneous reservoir displacement. It has been verified by a number of researchers that Adjustment of ion concentration in brine solutions, or adding surfactant solutions can enhance the oil recovery by altering the wettability. In the published literature, contact angle studies usually refer to measurement on calcite crystals and there are no results for the contact angle of carbonate porous media representative of reservoir rocks. Moreover, there are few studies on the effect of non-ionic surfactants, compared to those for ionic surfactants. Understanding the effect of various ions and their concentration in the injection brine on the wettability of the Limestone outcrop core samples is the first step for tailoring of the optimum injection brine. This will be followed by a study of the effect of surfactant on the wettability of calcite crystal samples. The evaluation of the results may provide guidelines for the design of injection brines for efficient enhanced oil recovery from carbonate reservoirs.
In this work, a procedure is established for the measurement of the contact angle on limestone outcrop core samples. Results showed that, at atmospheric conditions, low salinity CaCl2 solution induced the most significant improvement on the wettability of the outcrop sample. Moreover, among all the non-ionic surfactants studied, only the presence of the two first members of the 15S analogous series might lead to a slight decrease of the contact angle.
Xing, Dazun (University of Pittsburgh) | Wei, Bing (University of Pittsburgh) | McLendon, William J. (University of Pittsburgh) | Enick, Robert M. (University of Pittsburgh) | McNulty, Samuel (University of Pittsburgh) | Trickett, Kieran (University of Bristol) | Mohamed, Azmi (University of Bristol) | Cummings, Stephen (University of Bristol) | Eastoe, Julian (University of Bristol) | Rogers, Sarah (ISIS Facility Science and Technology Facilities Council) | Crandall, Dustin (URS Washington Division) | Tennant, Bryan (URS Washington Division) | McLendon, Thomas (US Department of Energy National Energy Technology Laboratory) | Romanov, Vyacheslav (US Department of Energy National Energy Technology Laboratory) | Soong, Yee (US Department of Energy National Energy Technology Laboratory)
Several commercially available, nonionic surfactants were identified that are capable of dissolving in carbon dioxide (CO2) in dilute concentration at typical minimum- miscibility-pressure (MMP) conditions and, upon mixing with brine in a high-pressure windowed cell, stabilizing CO2-in-brine foams. These slightly CO2-soluble, water-soluble surfactants include branched alkylphenol ethoxylates, branched alkyl ethoxylates, a fatty-acid-based surfactant, and a predominantly linear ethoxylated alcohol. Many of the surfactants were between 0.02 to 0.06 wt% soluble in CO2 at 1,500 psia and 25°C, and most demonstrated some capacity to stabilize foam. The most- stable foams observed in a high-pressure windowed cell were attained with branched alkylphenol ethoxylates, several of which were studied in high-pressure small-angle-neutron-scattering (HP SANS) tests, transient mobility tests using Berea sandstone cores, and high-pressure computed-tomography (CT)-imaging tests using polystyrene cores. HP SANS analysis of foams residing in a small windowed cell demonstrated that the nonylphenol ethoxylate SURFONIC® N-150 [15 ethylene oxide (EO) groups] generated emulsions with a greater concentration of droplets and a broader distribution of droplet sizes than the shorter-chain analogs with 9-12 ethoxylates. The in-situ formation of weak foams was verified during transient mobility tests by measuring the pressure drop across a Berea sandstone core as a CO2/surfactant solution was injected into a Berea sandstone core initially saturated with brine; the pressure-drop values when surfactant was dissolved in the CO2 were at least twice those attained when pure CO2 was injected into the same brine-saturated core. The greatest mobility reduction was achieved when surfactant was added both to the brine initially in the core and to the injected CO2. CT imaging of CO2 invading a polystyrene core initially saturated with 5 wt% KI brine indicated that despite the oil-wet nature of this medium, a sharp foam front propagated through the core, and CO2 fingers that formed in the absence of a surfactant were completely suppressed by foams formed because of the addition of nonylphenol ethoxylate surfactant to the CO2 or the brine.
Carboxybetaine viscoelastic surfactants have been applied in acid diversion and fracturing treatments in which high temperatures and low pH are usually involved. These surfactants are subjected to hydrolysis under such conditions because of the existence of a peptide group (-CO-NH-) in their molecules, leading to changes in the rheological properties of the acid. The objective of this paper is to study the impact of hydrolysis at high temperatures on the apparent viscosity of carboxybetaine viscoelastic surfactant-based acids, and propose the mechanism of viscosity changes by molecular dynamics (MD) simulations.
Surfactant-acid solutions with different compositions (surfactant concentration varied from 4 to 8 wt%) were incubated at 190°F for 1 to 6 hours. Solutions were then partially spent by CaCO3 until the sample pH was 4.5, and the apparent viscosity was measured using a high-temperature/high-pressure (HT/HP) viscometer. To understand the mechanism for viscosity changes on the molecular level, MD simulations were carried out on spent surfactant-acid aqueous systems using the Materials Studio 5.0 Package.
It was found that short-time hydrolysis at high temperatures (for example, 1 to 2 hours at 190°F) led to a significant increase in surfactant-acid viscosity. However, after incubation for 3 hours, phase separation occurred and the acid lost its viscosity. Simulation results showed that viscosity changes of amido-carboxybetaine surfactant acid by hydrolysis at high temperatures may be caused by different micellar structures formed by carboxybetaine and fatty acid soap, its hydrolysis product. The optimum molar ratio of amido-carboxybetaine and fatty acid soap to form worm-like micelles was found to be nearly 3:1 from our simulations.
Our results indicate that hydrolysis at high temperatures has a great impact on surfactant-acid rheological properties. Short time viscosity build-up and effective gel breakdown can be achieved if surfactant-acid treatments are carefully designed; otherwise, unexpected viscosity reduction and phase separation may occur, which will affect the outcome of acid treatments.
The oil-based drill solids are regarded as controlled or hazardous waste since it is contaminated with oil and other organic/inorganic contaminants. As such, the drill solids can be disposed with 3 different ways: (1) decontamination treatment before discharged into the sea; (2) re-injecting the drill solids into the well or (3) hazardous waste controlled landfill. The disposal of the drill solids in the landfills is usually the last environmental option. The lowest environmental impact way for the solid disposal, especially for offshore operation, is still a decontamination treatment before discharged. However, the conventional decontamination technology still exhibits limited efficiency to extract oil from the drill solids; yielding the oil content in the treated solids of much greater than 1% oil content in the dried solids, which does not meet a strict environmental regulation in many highly ecological-sensitive countries (e.g. UK and North Sea countries, etc.).
This paper demonstrates a new promising technology to overcome this efficiency limitation, called nanoemulsion. Nanoemulsion is a water-in-oil emulsion, having the Winsor type III or IV stages but with high surfactants-to-interface ratio. When analyze using dynamic light scattering, it shows the natural distribution of <100nm particle size. Nanoemulsion is able to provide ultralow interfacial tension (IFT) of <0.01mN/m. According to Laplace Pressure equation, when IFT is extremely low, less energy is required to remove the oil that trapped inside the pores. Recently Nanoemulsion has been demonstrated able to remove sticky oil-base mud inside the wellbore and able to suspend the mud after treatment. When using it to remove the oil from the drill solids, it is able to reduce the contact angle and capillary force on the solid particle surface, subsequently, allowed water to penetrate and wet the particle surface and accessible pores. This mechanism indeed converts the surfaces become water-wet (hydrophilic). Once the particles surfaces are water-wet, oil will instantly desorb from it and easily segregate through centrifuge force. Different proposed process will be shared and discussed in this work. It was found that the oil content in the drill solids after treatment with nanoemulsion cleaning process was able to reach <1%.
In order to screen various chemical and microbial EOR methods for core-flooding experiments and potential field trials, a laboratory investigation of evaluating the effect of micro-emulsion on the reduction of interfacial tension (IFT) was recently carried out at CSIRO by using commercially available chemical and bio-surfactants. Environment friendly non-ionic, anionic surfactants and a biosurfactant (Bacillus subtilis) were used to create micro-emulsion in an oil-brine system. Stable micro-emulsion (ME) was achieved by proportionally mixing various alcohols with surfactants.
Twenty-four micro-emulsion samples with five different chemical combinations were prepared for screening. All samples were stirred to create a stable ME phase. The volume changes of the ME phase were monitored over two weeks and their density, viscosity, and IFT were measured. The size distribution of ME phases was also characterised using optical microscopy equipped with an UV light source.
The micro-emulsion created by co-surfactants were found to be quite effective in reducing the oil-brine IFT and oil viscosity, and achieved ultra low IFT under reservoir pressure and temperature. There appears to be a linear relationship between the size of micro-emulsion and IFT reduction. ME with small sizes results in more IFT reduction and achieve stable ME at high temperature and pressure. Compared with the IFT reduction from the surfactant or microbial metabolism, the reduction of IFT through stable ME can be several orders of magnitude larger and may thus achieve better enhanced oil recovery in suitable reservoir systems.
Salym Petroleum Development (SPD) oil company is a joint venture between Shell and JSC Gazprom Neft. SPD currently holds three license areas in the south of Khanty-Mansiysk Autonomous Okrug. So far the company has concentrated its efforts on further exploration and development of ‘traditional deposits': from early production at the Upper Salym filed to commissioning state-of-the-art central oil production facility at the large West Salym field and the satellite Vadelyp field.
At the early stage of field development the company started to research ‘non-traditional' hydrocarbon resources. One group of these resources is immobile oil remaining in flooded reservoir after the waterflood target oil recovery factor had been achieved; another group of resources is Bazhenov Formation oil. These resources are not currently developed actively because of the combination of technological risks and current macroeconomic conditions in Russia. However, the study of analogous fields shows that the industry practice has successful solutions for both groups of the problems and non-traditional resources with the characteristics presented at the Salym group of oil fields are in fact successfully developed elsewhere (after elimination of technical risks through analytic work and field tests).
The work on the enhanced oil recovery project began with the high-level assessment of various technologies in 2007. In 2010 a more detailed study of potential technologies was carried out including high pressure air injection and low salinity waterflooding.
As a result of screening an EOR method of flooding with the solution of chemicals - Alkaline-Surfactant-Polymer - was chosen. Initial stages of the project comprised lab tests, core experiments and field tests. From these tests, an estimate of potential oil recovery factor increase of 15 %-20% (of STOIIP) was confirmed. In 2011 the ASP project reached maturity when the next stage would be implementation of the pilot project activities. Currently the work is on the way to design the flooding pattern and surface processing facilities with expected ASP oil production in 2014-2015.
In the beginning the article gives a short overview of the history and status of the project. After that it describes the stages of analytical work in Russian laboratories to find, optimize and test various types of Russian surfactants. This work was carried out under the guidance of the operator (Salym Petroleum) with the engagement of specialists from Shell and Gazprom Neft research centres. As a result lab samples of anionic surfactant showed satisfactory results during core flood experiments.
Finally it is worth mentioning that one of the results of the work was the establishment of methodological and experimental framework on the basis of Russian contractors and laboratories which made it possible to asses, within the short period of time, a large number of chemicals used on the Russian market for EOR activities.
Mackenzie, Cameron (LUX Assure) | Rowley-Williams, Catherine (LUX Assure) | Achour, Mohsen (ConocoPhillips Company) | Blumer, David (ConocoPhillips Company) | Joosten, Mike W. (ConocoPhillips Company) | Rowe, Max (University of Aberdeen)
This paper discusses the principle and proof of concept of a novel corrosion-management tool based on maintaining optimum corrosion-inhibitor dose in an inhibited environment. Film-forming corrosion inhibitors typically contain active ionic surfactant molecules, which adsorb on surfaces and form a protective barrier against corrosion. Upon saturation of surfaces by the inhibitor, the molecules are found in the aqueous phase as micelles or in the oil phase as reverse micelles. The proposed technique is based on the hypothesis that the presence of these micelles in the water phase could be used to indicate the total surface coverage and, therefore, the optimum dose.
The technique has been applied in the laboratory simulating an actual inhibited multiphase production system. Fluorescent markers, which are extremely sensitive to micelle presence, have been developed and used during the laboratory testing. Results were compared with those from standard laboratory techniques, including interfacial tension (IFT) and particle-size analyses (diffraction), in order to determine the efficacy for micelle detection. Corrosion bubble tests were also used to determine any link to inhibitor efficiency.
IFT results showed complex events occurring with increasing inhibitor concentration. The IFT vs. inhibitor concentration curve was nonclassical, probably because of the multicomponent nature of inhibitor formulations, but suggested micelle formation at approximately 150 ppm. Fluorescence analysis suggested that micelles formed starting at a 150-ppm dose. Particle-size analysis was consistent with micelle presence beyond this concentration. Separate experiments comparing fluorescence with corrosion rates demonstrated an apparent nonlinear variance with inhibitor concentration, supporting the hypothesis.
The analytical comparisons supported the underlying principles of this micelle-detection technology. Development of a portable device is under way and will provide an important new tool for proactive corrosion management in the oil field as well as a useful laboratory qualification method.
Kalra, Amrit (Shell International Exploration and Production) | Venkatraman, Ashwin (Shell International Exploration and Production) | Raney, Kirk H. (Shell International Exploration and Production) | Dindoruk, Birol (Shell International Exploration and Production)
Oil production is generally a complicated multiphase flow inside pipelines, with possible water-in-oil (W/O) emulsions present with other usual phases such as free water and free oil. The W/O emulsions formed can present significant hurdles in production facilities for pumping fluids and during pipeline transport. It is well known that high shear rates provided by pumps, chokes, or valves result in stable emulsion behavior for a field in primary production. Several field tests are under way to test the potential of surfactant flooding as a tertiary-recovery mechanism. The effect of addition of surfactants on the emulsion rheology of production fluids, as in alkaline/surfactant/polymer (ASP) flooding, is not very well understood. This understanding of W/O-emulsion rheology in ASP-injection oil recovery is essential for design of pumps and pipelines as well as for handling flow-assurance issues.
In this paper, we report results from experiments as well as modeling of W/O-emulsion rheology that can form during ASP injections. We focus here only on the alkaline/surfactant (AS) part of these injections in order to clearly understand the impact of surfactants, removing the uncertainities that come with large rheology changes with polymer addition. The effect of surfactants on the rheology of W/O emulsions was studied by making two different types of emulsions: (1) native-brine W/O emulsions without surfactants to provide a baseline and (2) brine W/O emulsions with surfactants used in ASP injections. This way, the impact of ASP injections on emulsion rheology can easily be quantified. A new correlation is developed, based on in-house historical experimental data, to describe rheology of emulsions without surfactants. This correlation should assist in managing the uncertainties that come from extrapolating emulsion rheology measured in the laboratory to actual field conditions. Further, to understand the effect of ASP injections, new experimental measurements were made by adding surfactants to brine solutions. The addition of surfactants resulted in different rheology as compared with emulsions formed by brine solutions. These differences have been attributed to the W/O interfacial tension (IFT), and IFT was added to modify the original correlation. To our knowledge, this is the first study that explicitly relates emulsion rheology with IFT.
This paper builds on the evidence for the optimum dose of organic film-forming corrosion inhibitor (FCCI) being at the critical micelle concentration (CMC) of the surfactant components, and the concept of micelle detection as a tool for understanding the effectiveness of the inhibitor dose in the field, which has been presented previously. It extends the underlying principles from laboratory testing, to the rapid analysis of field fluids and explores the different results available from alternative instrumentation.
An inhibitor optimisation trial was undertaken on an offshore oil production platform for protection of a subsea pipeline used to tie back wells 10 miles from the platform. Two micelle detection devices were used, both primarily using fluorescence detection - a simple handheld device for offshore testing and a more complex device used for testing shipped samples in an onshore lab. Electrochemical corrosion monitoring was also used to analyse the produced fluids as the inhibitor dose was varied from zero to 200% of the estimated optimum dose.
Results were clouded by a number of operational issues outside the control of the experiment but interpretation of the whole suggested that the offshore portable micelle analysis was overcome by large quantities of dispersed oil which masked the optical process. However the onshore testing gave some promising results, demonstrating a correlation between increased micelle levels and high inhibitor dose and suggesting that the original dose was sub-optimal.
These experiments supported the need to use the more complex instrument to be able to detect micelles in very impure systems. Making and testing such a device suitable for field operations is now a priority.
Walker, Dustin (U. of Texas at Austin) | Britton, Chris (U. of Texas at Austin) | Kim, Do Hoon (U. of Texas at Austin) | Dufour, Sophie (YPF Argentina) | Weerasooriya, Upali (U. of Texas at Austin) | Pope, Gary Arnold (U. of Texas at Austin)
The physical structure of microemulsions and the degree to which ultra-low IFT is achieved is dependent on a number of parameters including the types and concentrations of surfactants, co-solvents and alkali, crude oil composition, brine composition, temperature and to a lesser extent, pressure. Modifying any one of these variables creates a microemulsion with different properties. The rheological properties of the microemulsion must be adjusted appropriately to achieve good performance under practical reservoir conditions. Two microemulsion properties of primary concern are undesirably high viscosity relative to oil viscosity and non-Newtonian behavior. The broader implications of injecting microemulsions with high viscosities or non-Newtonian behavior in the field include high surfactant retention, unsustainably high pressure gradients, reduced sweep efficiency and microemulsions that stagnate in the field due to high viscosity at low shear rates. The most common ways to reduce microemulsion viscosity are to optimize the surfactant formulation with a good co-solvent and/or by adding more branching to the surfactant hydrophobe. Adding co-solvent in appropriate concentrations makes a microemulsion much less viscous. However, co-solvents increase the cost and complexity and also tend to increase the IFT. A less conventional solution involves increasing the temperature of the injection water thereby lowering both the oil and microemulsion viscosity. This approach has been tested successfully in core floods using both surrogate and reservoir cores.