Research has discovered systems that can selectively flocculate mineral solids from a high molecular weight polymer flood matrix while leaving the polymer intact or alternatively achieving a viable total flocculation of the polymer in the produced fluids. Modified alkaline surfactant polymer (ASP) and standard polymer (P) flood systems were studied with findings obtained by controlled variations of both well-proven and non-prevalent chemical approaches. Results concluded that selectively removing the mineral solids from polymer-laden water produces reusable enhanced oil recovery (EOR) fluid.
EOR is a proven method to increase hydrocarbon yield from post-natural, stimulated, or standard flood driven reservoirs. Fluid produced from the reservoir contains the desired hydrocarbon and an aqueous phase. Previously considered a liability, properly treated, the aqueous phase can become an asset. Polymer floods have a proven history in EOR and, though complex in application, ASP also demonstrated EOR effectiveness in the laboratory. Most ASP approaches are currently in field trial stages. The produced fluid is subjected to hydrocarbon separation with the resulting aqueous system either treated for disposal or recycled into the system. The aqueous phase matrix is mainly composed of high molecular weight polymer, mineral solids, residual base, residual oil, and possibly surfactant. If the producer chooses disposal, the solids must be flocculated by a method balancing density, dewaterability, processability, process variability, and cost. However, if the producer opts to recycle the fluid for reinjection, steps must be taken to minimize polymer deviations requiring selective flocculation of all components with exception of the polymer. This undertaking is challenging as EOR polymers are also effective flocculants, therefore sensitive to standard coagulant and flocculant approaches. Utilizing controlled, standard methods and multivariable design of experiments, results were obtained for both total and selective flocculation.
Total flocculation systematically studies the influence of pH, inorganic, and organic coagulants in maximizing the treatment effectiveness. The same approach was successful for selective flocculation, however unique coagulants were applied. The selective flocculation process coagulated and separated the mineral solids, and left the high molecular weight polymer intact and the fluid matrix as viscous as prior to treatment. Effectiveness of treatments were determined using standard gravimetric and viscometric methods.
These discoveries will assist decision makers in determining whether total or selective flocculation is the most viable treatment for polymer based EOR, balancing environmental and economic aspects to pursue a desired treatment route. These methods, though targeting EOR, have practical applications for treatment of flowback and water produced from stimulation and potentially drilling operations as well.
The performance results from a systematic study of novel and contemporary clay stabilizers are provided. These interactions range from synergistic to antagonistic and are presented on a response surface with good correlation. Both organic and inorganic permanent and temporary clay stabilizers were studied. Some of these novel effective inhibitors have HIMS ratings lower than choline chloride.
Various clay stabilizers are employed when stimulation techniques requiring aqueous based fluids are necessary in water sensitive formations. Typically, if swelling or migrating clays are present, temporary or permanent stabilizers are utilized. Low molecular weight temporary stabilizers, as a rule, perform only above a critical level concentration, but as the stabilizer's concentration diminishes in the fracturing fluid due to flowback, formation fluid displacement, or other mechanisms, the clay can swell, reducing porosity and permeability. Permanent stabilizers are generally higher molecular weight and can adhere to single or multiple clay platelets, thus dissolution of the stabilizer into the fluid is not favored, and the beneficial anti-swelling effect is of higher duration.
This study was set up using Central Composite Design of Experiments. Performance testing was conducted using a low pressure Bariod fluid loss cell. A set concentration of unbenefited sodium bentonite was blended into water at a specific RPM and duration in the presence of the particular stabilizers, then placed in the cell, sealed, and pressure was applied. Finally leak off rates were measured. The slope of the leak off curve was calculated and plotted versus dosage. The slopes and response surfaces observed had excellent correlation. Additive effects and synergies were noted.
The design of efficient temporary clay stabilizers can be directly linked to performance. Novel temporary clay stabilizers competitive with choline chloride in both performance and environmental profile should be welcomed in stimulation. The duration of the stabilization could also be studied using this test method since porous media experimentation is difficult to perform.
The performance of systematically substituted temporary clay stabilizers has significant correlation with performances predicted by computational modeling. The model binding energies of different clay stabilizers onto various bentonite crystalline faces were independently calculated and corresponded well with a standard bench-top performance method indicating a systematic approach in the development of temporary clay stabilization performance may be realized.
Various clay stabilizers are employed when stimulation requiring aqueous based fluids is necessary in water sensitive formations. Typically, if swelling or migrating clays are present, temporary or permanent stabilizers are utilized. Low molecular weight temporary stabilizers as a rule perform above a critical level concentration, but as the stabilizers concentration diminishes in the fracturing fluid due to flowback, formation fluid displacement, or other mechanisms, the clay can swell reducing porosity and permeability. Permanent stabilizers are generally higher molecular weight and can adhere to single or multiple clay platelets thus dissolution of the stabilizer into the fluid is not favored and the beneficial anti-swell effect is of higher duration. It was discovered when using binding energies of substituted ammonium ions on a bentonite interlayer, the binding energies correlated well with performance testing.
The binding energy of ammonium ions substituted with 0 to 4 methyl groups or choline were calculated on the 001 crystal face(s) of bentonite. Bentonite being a 2:1 swelling clay had its inter-crystalline space gapped at 8 to 20Å. Unique molecular ions were introduced to this space and the binding energies were calculated using a Monte Carlo Isothermal Adsorption method. Performance testing was then conducted using a low pressure Bariod fluid loss cell. A set concentration of sodium bentonite was blended into water a specific RPM and duration in the presence of the particular ammonium ion, placed in the cell and pressure was applied and leak off rate were measured. The resulting leak off rates were compared to the binding energy.
The design of efficient temporary clay stabilizers can be directly linked to performance. Further, the duration of the stabilization may also be modeled in a way where experimentation would be difficult in flow through porous media.
Rheological experiments have been conducted with commercial and experimental friction reducers indicating certain profiles are advantageous for performance. In these profiles the factors of time and concentration are important in predicting the maximum performance window. These windows become apparent without the use of sophisticated rheological instrumentation.
The viscosity profile of a friction reducer is dependent on factors such as polymer charge, charge distribution, molecular weight, polymer concentration, solvent properties, specific shear rate and time. Often it is difficult to measure properties such as molecular weight and viscosity, both quite sensitive to the specific test method and many assumptions are made. In this study, the viscosity of the system depends on the shear history, concentration, and time of measurement. Most traditional viscosity methods assume a thermodynamic definition of polymer configuration. This assumption is valid for measurement of friction reduction after significant duration. However, in a hydraulic fracture, this time may not be realized during the volumetric transfer of the fluid from the pumps to the perforations. In a recirculating friction loop measurement, the friction reduction performance of an ideal candidate rapidly increases and then sometimes diminishes with recirculation time. A possible correspondence between this phenomenon can be linked to the measurement conducted in this study.
Shear rate sweeps were conducted on a variety of synthetic polymers with a Couette rheometer and a microchip rheometer. Variables studied were polymer type, concentration, shear history, time, solvent, make-down procedure, and atmosphere. Both inverse emulsion and dry friction reducers were studied. Friction reduction was measured on a once through system.
From this study, ideal friction reducer candidates can be selected by simply and rapidly examining the rheological profile and rheological nuances realized when conducting the measurements. When choosing an ideal friction reducer, it must perform rapidly and maintain the necessary friction reduction required for the time frame needed.
There is a new chemical improved oil recovery (IOR) process for Bakken reservoirs. In this concept a custom surfactant agent may be incorporated into standard hydraulic fracturing treatments for the Bakken to increase oil recovery. These are reservoirs from the Late Devonian to Early Mississippian age occupying about 200,000 square miles (520,000 km2) of the subsurface of the Williston Basin, covering parts of Montana, North Dakota, and Saskatchewan. The rock formation consists of three members: Lower shale, Middle dolostone/siltstone, and Upper shale. The shales were deposited in relatively deep marine conditions, and the dolostone/siltstone was deposited as a coastal carbonate during a time of shallower water. The Middle member is the principal oil reservoir, roughly two miles (3.2 km) below the surface. Both the Lower and Upper members are organic-rich marine shales.
The oil in place in the Bakken shale play is very large, with an April 2008 USGS report estimating the amount of technically recoverable oil in the Bakken Formation at 3.0 to 4.3 billion barrels. Production from the Bakken has been limited in the past, but now has become a very active area of development with the widespread advent of drilling horizontal wells and large-volume hydraulic fracturing treatments. One key to the economic production rates of oil from these formations is to create an extensive well-connected fracture system.
Laboratory experiments demonstrate that specialized surfactant formulations will interact with this mixed- to oil-wet low permeability Middle member to produce more oil. Specifically, including such a surfactant chemical formulation in an aqueous phase (e.g. hydraulic fracturing fluids) will promote the spontaneous imbibition of this fluid into the tight matrix and microfractures containing high oil saturation. This promotes expulsion of oil otherwise trapped to migrate into the fracture system and then be produced into the wellbore. Thus including an appropriate surfactant in frac fluids or in other aqueous-based treatment fluids can produce additional oil.
In order to achieve in-depth control of injection water and improve oil recovery, a new profile control agent called dispersed particle gel (DPG) is developed, which is significantly different from colloidal dispersion gel both in its preparation and its characteristics. The DPG is prepared by the tube shearing cross-linking method with polymer and cross-linker. Atomic force microscope (AFM) studies show that DPG is made of small pseudo-spherical particles and the sizes can be controlled from nm to mm by adjusting shearing rate in the tube. The particles have a ratio of major and minor axis length of near 1, and the larger the shear rate, the closer the ratio is to 1. Salinity has a minor effect on the micro-morphology and there is an aging aggregation phenomenon. The results on dynamic light scattering also support the conclusions above. The rotary viscometer measurements show that DPG has a low viscosity, and salinity has a minor effect on viscosity, and that the DPG has good shearing stability. Physical simulation experiments in this study demonstrate that DPG has good injectivity, the ability to control injection profile, and improve oil recovery. It can be concluded from this study that this new profile control agent has the potential for wide application.
Iglauer, Stefan (Imperial College) | Wu, Yongfu (Missouri U of Science & Tech) | Shuler, Patrick J. (ChemEOR) | Tang, Yongchun (California Inst. of Technology) | Goddard, William A. (California Inst. of Technology)
We present Alkyl polyglycoside (APG)/1-naphthol formulations which show ultra-low interfacial tensions (IFT) against n-octane. We demonstrate that 1-naphthol is very efficient as a cosolvent in terms of reducing IFT. These formulations are therefore potentially suitable as agents for enhanced oil recovery (EOR). An increasing APG concentration strongly increased viscosity, and the formulations showed shear-thinning behavior. In a coreflood EOR test we showed that this type of formulation significantly increased oil production.
Keywords: alkyl polyglucoside, 1-naphthol, ultra-low interfacial tension, cosolvent, shear-thinning, enhanced oil recovery, surfactant flooding.
Large quantities of Alkyl polyglucoside (APG) are produced industrially nowadays (80000 t/a, Hill and Rhode 1999) and this surfactant class is widely used in a range of applications including cosmetics, pharmacy, detergency, agriculture and oil recovery (Balzer and Lüders 2000, Balzer 1991, Hill and von Rybinski 1997, Hill and Rhode 1999, Pakpayat et al. 2009).
During our studies we found that APG formulations can reach low to ultra-low interfacial tension (IFT) values against liquid hydrocarbons (Goddard et al. 2004, Iglauer et al. 2009+2004a,b, Wu et al. 2004), consistent with literature data (Kahl et al. 1996, Förster et al. 1996, von Rybinski et al. 1998, Balzer 1991, Kahlweit et al. 1995). In general, the IFTs of these APG formulations were quasi-independent of temperature or salinity (Balzer and Lüders 2000, Hill and von Rybinski 1997, Iglauer et al. 2009, Kahlweit et al. 1995), which is very useful for enhanced oil recovery (EOR) applications, because geological formation temperature and/or salinity can vary substantially (Green and Willhite 1998).
Low IFT generating formulations are sought for EOR applications in order to mobilize residual crude oil which is trapped as isolated pore-scale bubbles in small rock pores by capillary forces. Surfactant formulations reduce these capillary forces enabling the residual oil to be produced (Green and Willhite 1998, Abrams 1975).
We identified 1-naphthol as a very efficient cosolvent which was able to reduce the IFT of APG formulations to ultra-low levels at low concentrations. In addition, we conducted rheological measurements, because the rheological behavior of the formulations is of great importance as it determines injection rate and pressure. We present our experimental data for these formulations and discuss their potential as EOR agents in the context of a coreflood experiment we conducted.
This paper presents an evaluation of different chemical agents that can reduce dramatically the apparent viscosity of a heavy crude oil or a thick emulsion. The focus of this study is on methods to improve the production of heavy oils and very viscous emulsions such as are found in California, Canada, and Venezuela. This study identified several surfactant-demulsifier formulations that can reduce the viscosity of such heavy fluids by as much as 3 orders of magnitude.
If efficient chemical solutions are applied downhole to reduce produced fluids viscosity this offers an economical means to reduce the energy required to move the oil between the well to the surface facilities, thereby improving well productivity and reducing lifting costs. It is especially suited for wells that are producing fluids at colder temperatures (less than 150 °F) that have extreme fluid viscosities (from 10,000 to 100,000 cp); these may be reduced to 100 - 500 cp by gentle mixing with aqueous-based chemical treatment solutions. Wells with high hydraulic pressures, poor pump efficiencies, or excessive pressure losses in the facility gathering systems are good candidates for these treatments. Reducing these extreme viscosities will have benefits such as lowering the power consumption to lift the produced fluids and reduce system pressures. Chemical costs for such chemical treatments are less than a dollar a barrel of oil, and can be even less than $0.50 per barrel of heavy oil.
These same or similar chemical systems also may be beneficial for longer distance transportation of heavy oils, as pre-treatments for cyclic steam treatments, or as additives in the stimulation fluids applied in heavy oil wells. .
This laboratory investigation employed a unique novel viscometer that will measure accurately the effective dynamic viscosity of multi-phase liquids (emulsions) from several centiposes to thousands of centipoise. This instrument was developed to overcome the limitations of conventional laboratory viscometers to measure unstable emulsions that may separate during the measurement process.
Dai, Caili (China University of Petroleum East China) | You, Qing (Peking University and China University of Petroleum East China) | Wang, Yefei (China University of Petroleum East China) | Zhao, Fulin (China University of Petroleum East China) | Shuler, Patrick J. (ChemEOR)
There is a large amount of residual polymer existing in the forms of solution, adsorption and entrapment in formation after polymer flooding. Then the water cut increases quickly along high permeable zone when displacing water. In order to improve sweep efficiency of water flooding and fully use residual polymer in formation, the reutilization technology of residual polymer in formation is proposed and developed. When the reutilization agents (including flocculating agent and fixed agent) are injected, they react with residual polymer and the floc units as well as the cross-linking units are formed which could block high permeability zone and control cross flow. As a result, the sweep efficiency of water flooding and oil recovery could be enhanced. In this paper, the optimized flocculating agent was selected through suspension experiments and the fixed effect for polymer was studied in sand pack cores, and the residual resistance factor was used as the evaluation criterion. The experiments showed that solid particles can be used as flocculating agent and the optimized flocculating agent is stabilized sodium clay; the cross-linking agent can be used as fixed agent and the optimal fixed agent is selected depending on formation temperature and the salinity. This technology was successfully applied in Henan oilfield, Shengli oilfield and Daqing oilfield. The water cut and produced polymer concentration decreased dramatically and oil production increased obviously. This technology which belongs to quaternary oil recovery is a preferred improved oil recovery technology after polymer flooding and has abroad application prospect.