It is now common knowledge among EOR practitioners that the combination of ferrous iron (Fe2+) and oxygen causes severe oxidative degradation to EOR polymers, resulting in a lowering of molecular weight and hence a loss of viscosity. During the design of polymer flooding projects, an important question is thus the acceptable levels of Fe2+ and dissolved oxygen that can be tolerated in injection water specifications. Furthermore, we would like to be able to predict the extent of degradation in the case of excess Fe2+ or oxygen ingress.
However, despite over fifty years of research and a general understanding of the degradation mechanism involved, quantitative prediction of the extent of degradation has proven elusive and dependent on the measurement protocol. This is likely due to the fastidious experimental protocols required to work under anaerobic or limited-oxygen conditions.
We examine existing protocols and demonstrate that experiments in which either Fe2+ or oxygen are the limiting reagent yield equivalent results when the stoechiometry of the Fe2+ oxidation reaction with oxygen is taken into account. Based upon these findings, a novel, easy approach is proposed to quantify polymer oxidative degradation as a function of either dissolved oxygen or Fe2+ content.
The limits of 225 ppb Fe2+ and 32 ppb dissolved oxygen are fixed for Flopaam 3630S in 6 g/l brine in the concentration range 500-1500ppm in order to ensure degradation of low-shear plateau viscosity does not exceed 10%. Higher levels will lead to severe polymer degradation. The influence of polymer concentration, temperature and salinity is also investigated. At last, evolution of redox potential and pH during Fe2+ oxidation are discussed.
There is a direct practical application of these finding for the design of surface facilities for polymer dissolution and transport and for the prediction of degradation in case of oxygen ingress. Moreover, a simple and easily performed protocol is proposed for the evaluation of polymer oxidative degradation.
Davidson, Andrew (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Unomah, Michael (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan
Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.
Fluorinated benzoic acids (FBA) have been widely used in the oil industry as conservative tracers. However, some of these tracers have been shown to rapidly degrade when tested at temperatures above 121°C within three weeks. Naphthalene sulfonates (NSAs) have been shown to be excellent tracers in geothermal applications. However, a broader study was required to determine tracer conservation in reservoir fluids and formations typically encountered in the oil field.
In this study we compare the oil field industry standard FBA tracers to NSA tracers under dynamic test conditions in the presence of reservoir oil, sandstone, carbonates and clays. We also compare the two sets of tracers under static conditions in the presence of four crude oils and different clay mineralogy to establish tracer conservation. Seven different sodium salts of naphthalene sulfonic acids were tested to determine if the tracers were adsorbed onto natural porous media (reservoir rock) at reservoir conditions. A broad range of conditions were selected to target typical reservoirs encountered. In addition, reservoir rock and a pseudo formation containing 10 Wt.% clay in silica sand were used in sand packs saturated with surrogate brine to ensure the tracer recovery under dynamic conditions.
High pressure liquid chromatography (HPLC-FLD) separation was used for simultaneous detection of seven NSAs while FBAs were analyzed using HPLC-UV. GC analysis of isopropyl alcohol (IPA) was used as a standard against which the others were measured.
Dynamic tracer tests demonstrated that the sodium salts of naphthalene sulfonates behaved similarly to the control, IPA, with none of the tracers adsorbing on to the rock surface or partitioning into the oil phase. The naphthalene sulfonates can be successfully used as conservative tracers most specifically for high temperature applications. NSA tracers are an attractive replacement for conservative FBA tracers in the oil field due to their superior thermal stability, solubility in oil field brine, lower detection limits and cost.
Mishra, Ashok (Conoco Phillips) | Abbas, Sayeed (Conoco Phillips) | Braden, John (Conoco Phillips) | Hazen, Mike (Conoco Phillips) | Li, Gaoming (Conoco Phillips) | Peirce, John (Conoco Phillips) | Smith, David D. (Conoco Phillips) | Lantz, Michael (TIORCO, a Nalco Champion Company)
This paper is a field case review of the process and methodologies used to identify, characterize, design, and execute a solution for a waterflood conformance problem in the Kuparuk River Unit in late 2013. In addition, post treatment analysis in a complex WAG flood will be discussed. The Kuparuk River Field is a highly fractured and faulted, multi-layer sandstone reservoir located on the North Slope of Alaska. Large scale water injection in the field was initiated in 1981 and overall the field responded favorably to waterflood operations. In 1996, Kuparuk implemented a miscible WAG flood in many areas of the field. However, natural fault and fracture connectivity has resulted in some significant conformance issues between high angle wells in the periphery. Methodologies employed to identify and characterize one specific conformance issue will be outlined. Details of diagnostic efforts, and how they were used to identify, characterize and mitigate an injector/producer interaction through a void space conduit will be discussed. The solution selected to resolve this conformance issue involved pumping a large crosslinked hydrolyzed polyacrylamide (HPAM) gel system. The solution used a tapered concentration design with one of the highest molecular weight HPAM polymers available. Before execution of this solution, extensive history matching and modeling of the solution design and benefits were used to justify this effort. These modeling efforts and their projections will be reviewed. This solution was pumped into the offending injector in late 2013, and offset producers were carefully monitored for gel breakthrough. The polymer treatment design parameters, including rates and pressure limits were used to generate an effective solution. A discussion of this active design approach, a complete review of the well problem dynamics, treatment operations, products used, and potential complications associated with these products will be discussed. Post solution execution performance analysis was difficult due to the active nature of this MWAG flood. A variety of plotting and analysis techniques were used to identify and quantify the results. A discussion of these results will be provided. Finally, a summary of lessons learned, and a limited discussion of future plans will be presented.
Lee, Jason (University of Pittsburgh) | Dhuwe, Aman (University of Pittsburgh) | Cummings, Stephen D. (University of Pittsburgh) | Beckman, Eric J. (University of Pittsburgh) | Enick, Robert M. (University of Pittsburgh) | Doherty, Mark (GE Global Research) | O'Brien, Michael (GE Global Research) | Perry, Robert (GE Global Research) | Soong, Yee (US DOE NETL) | Fazio, Jim (US DOE NETL) | McClendon, Thomas R. (US DOE NETL)
CO2 miscible and immiscible displacements and hydrocarbon miscible floods are commonly plagued by low volumetric sweep efficiency, early gas breakthrough, high gas utilization ratios, and significant gas re-compression and recycle. Rather than addressing these problems via the water-alternating-gas (WAG) injection sequence that reduces gas relative permeability or the generation of gas-in-brine foams for reduced mobility, we propose increasing the viscosity of high pressure CO2 or NGL via the dissolution of dilute concentrations of thickening agents.
There are two strategies for increasing the viscosity of high pressure fluids; the dissolution of ultrahigh molecular weight polymers or associating polymers, or the dissolution of small molecules that self-assemble in solution to form viscosity-enhancing linear or helical supramolecular structures. Ideally a very small amount of the thickener will be required (roughly 0.1wt%) to elevate the CO2 or NGL viscosity to the same value as the oil being displaced (typically a 10-100 fold increase). Further, the thickened CO2 or thickened NGL should be a stable, transparent solution that does not require a heating/cooling cycle for viscosity enhancement to occur.
Thickener solubility and viscosity were determined over a 25-100oC range. Each of the three major NGL constituents (ethane, propane and butane) was thickened with an ultrahigh molecular polymer (commercial drag reducing agent), resulting in a 2-30 fold increase in viscosity at polymer concentrations of 0.5wt% or less. The polymer dissolved at the lowest pressure in butane and was most effective as a thickener in butane.
Three small molecule thickeners were identified for the NGL constituents; tri-alkyl-tin fluoride, hydroxyaluminum disoap, and a phosphate ester-crosslinker mixture. Remarkable viscosity enhancements were attained for propane and butane with the tri-alkyl-tin fluoride and aluminum soap; the crosslinked phosphate ester solutions exhibited modest viscosity increases. Only tri-alkyl-tin fluoride thickened ethane.
CO2 thickeners were assessed with a falling ball viscometer and pressure drop associated with flow through Berea sandstone. 4-5 fold increases in viscosity were attained with 1wt% of a high molecular weight polyfluoroacrylate. 3-4 fold increases in viscosity were attained with 1wt% high molecular weight polydimethyl siloxane, but a very large amount of toluene co-solvent was required. Although a remarkably effective small molecule thickener was designed for CO2 (100-fold increase at 1.3wt%), it required a heating/cooling cycle and a very large amount of hexane co-solvent.
We have identified the first polymeric and small molecule thickeners ever reported for ethane. Further, this study presents the largest viscosity increases ever reported for propane and butane with polymers and small molecule thickeners. We have presented the most effective polymeric thickeners for CO2 reported to date. This paper also summarizes numerous molecular architectures that are not viable for CO2 and highlights the most promising compounds that continue to be refined.
Water-based polymers are often used to improve oil recovery by increasing displacement sweep efficiency. However, recent laboratory and field work has suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation. The objective of this work is to investigate the effect of viscoelastic polymers on residual oil saturation in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120cp) and then waterflooded to residual oil saturation using brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM).
Significant reduction in residual oil was observed for all core floods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number,
One of the primary problems for mature oilfield operators is the production of undesired fluids, such as water or gas. Cantarell is a mature field wherein one of the greatest challenges is managing produced water. Mature oil fields experience severe water production, which can be challenging in naturally fractured carbonate reservoirs that produce through a thick layer of oil. A new technology combining two conformance systems was used to alleviate water production in a well in this field, returning production to optimal levels.
The study well (Well A) was shut in because of high water cut (90 to 100%), and post-analysis of this problem showed water coning from fractures in the Lower Cretaceous formation. The well has a unique interval, and perforating a deeper interval was not possible because the water-oil contact (WOC) was close. The solution selected for this case was a combination of two conformance technologies for water control that permit sealing high permeability channels and fractures and, more importantly, help provide selective water control—one is a swelling polymer designed to shut off water channels, fractures, or highly vugular zones, and the other is hydrocarbon-based slurry cement that reacts on contact with water. The result was the recovery of a producer well with 1,197 BOPD with 14% water cut. After 19 months, production averaged 1,300 BOPD for that month with 40 to 66% water cut.
Correctly diagnosing the problem and combining conformance technologies can help operators resume production of wells considered lost because of undesired fluids production. Therefore, this technology could be used to benefit reservoir optimization and production.
The prediction of polymer degradation under reservoir conditions is critical to EOR polymer selection. NMR studies were used to monitor the changes in the anionic content of acrylamide containing polymers. The monomer sequence distribution of hydrolyzed polyacrylamide polymers (HPAM) was monitored during lab test to improve our understanding of HPAM stability. The results suggest that accelerated aging of a polymer at reservoir conditions at elevated temperatures will result in a polymer with structure similar to the polymer resulting from extended aging at lower temperatures.
This paper examines whether retention of partially hydrolyzed polyacrylamide (HPAM) is different under anaerobic versus aerobic conditions. Both static (mixing with loose sand) and dynamic methods (core floods) were used to determine HPAM retention. There are both advantages and disadvantages associated with determining polymer retention using static tests versus dynamic tests and using aerobic versus anaerobic conditions. From static retention measurements, polymer adsorption values on pure silica sand or Berea sandstone were small, and they showed little difference between experiments conducted aerobically or anaerobically. For both aerobic and anaerobic conditions, HPAM retention increased significantly with increased pyrite or siderite content. Static retention under anaerobic conditions ranged from 45-75 µg/g with 1% of either pyrite or siderite to 137-174 µg/g for 10% pyrite or siderite to 1161-1249 µg/g for 100% pyrite or siderite.
If iron minerals are present, the most representative polymer retention results are obtained (for both static and dynamic tests) if conditions are anaerobic. Retention values (from static measurements) under aerobic conditions were commonly twice those determined under anaerobic conditions. If iron minerals are present and retention tests are performed under aerobic conditions, TOC or some similar method should be used for polymer detection. Viscosity detection of polymer may provide retention values that are too high (because oxidative degradation can be misinterpreted as polymer retention). For a broad range of siderite content, retention from static tests did not depend on whether dissolved oxygen was present. However, for a broad range of pyrite content, HPAM retention was significantly lower in the absence of dissolved oxygen than under aerobic conditions. Theses results may be tied to iron solubility. When polymer solutions were mixed with 100% pyrite over the course of 12 hours, 360–480-ppm iron dissolved into polymer solutions under both aerobic and anaerobic conditions, whereas with 100% siderite, only 0–0.6-ppm iron dissolved. If dynamic methods (i.e., corefloods) are used to determine polymer retention under aerobic conditions, flow rates should be representative of the field application. Rates that are too high lead to underestimation of polymer retention. With 10% pyrite, dynamic retention was 211 µg/g at 6 ft/d versus 43.2 µg/g at 30 ft/d. In contrast, retention values were fairly consistent (40.6 – 47.8 µg/g) between 6 ft/d and 33 ft/d under anaerobic conditions.
This paper addresses two questions for polymer flooding. First, what polymer solution viscosity should be injected? A base-case reservoir-engineering method is present for making that decision, which focuses on waterflood mobility ratios and the permeability contrast in the reservoir. However, some current field applications use injected polymer viscosities that deviate substantially from this methodology. At one end of the range, Canadian projects inject only 30-cp polymer solutions to displace 1000-3000-cp oil. Logic given to support this choice include (1) the mobility ratio in an unfavorable displacement is not as bad as indicated by the endpoint mobility ratio, (2) economics limit use of higher polymer concentrations, (3) some improvement in mobility ratio is better than a straight waterflood, (4) a belief that the polymer will provide a substantial residual resistance factor (permeability reduction), and (5) injectivity limits the allowable viscosity of the injected fluid. At the other end of the range, a project in Daqing, China, injected 150-300-cp polymer solutions to displace 10-cp oil. The primary reason given for this choice was a belief that high molecular weight viscoelastic HPAM polymers can reduce the residual oil saturation below that expected for a waterflood or for less viscous polymer floods. This paper will examine the validity of each of these beliefs.
The second question is: when should polymer injection be stopped or reduced? For existing polymer floods, this question is particularly relevant in the current low oil-price environment. Should these projects be switched to water injection immediately? Should the polymer concentration be reduced or graded? Should the polymer concentration stay the same but reduce the injection rate? These questions are discussed.