Hydraulic fracturing plays an important role in maximizing the recovery of oil and gas in North America. Viscoelastic surfactant based fluids (VES) are an important class of fracturing fluids (Ghaithan, 2014). They are reputed to cause less formation damage during the fracturing process and break cleaner, leaving less material in the formation to impede the flow of hydrocarbons (
Carbohydrates have the ability to react with a variety of substances and can be conveniently cross-linked to form polycationic materials. As such, molecules can be created that mimic the polymer backbones used in fracturing fluids today, potentially eliminating some of the negative side effects of those same polymers. Carbohydrate-based, polycationic molecules are created from bio-renewable resources such as sucrose and vegetable oils. The incorporation of ether links and short-chain components within these molecules imply a better biodegradation profile and lower toxicity than traditional long-chain cationics.
Several new polycationic, carbohydrate molecules were synthesized in the lab in order to demonstrate the flexibility and range of the chemistry and explore structure-activity relationships. When formulated into viscoelastic fluids, smaller polycationics demonstrated excellent tolerance to salts, at times requiring the presence of salts in order to show viscoelasticity with enough viscosity to suspend proppant. In addition, as the number of crosslinkers per molecule increased, the resultant formulated viscosity increased, however the tolerance to salt decreased.
Temperature plays an important role when acidizing wells using proper acid-stimulation techniques. Typically, with increasing temperatures, stimulation of carbonate formations using hydrochloric acid (HCl) becomes less of a viable candidate for a myriad of reasons, including near-wellbore (NWB) spending and increased corrosion attributed to the aggressive and reactive nature of HCl. While corrosion can be tamed using a proper corrosion inhibitor, NWB spending of the acid cannot be eliminated or reduced without retarding the acid with oil/polymer emulsions or foams. Albeit, efficacy of both has shown to tame this reactive nature, breaking the emulsion or foam can lead to formation damage, incomplete acid spending, or additional pumping stages, all of which add complexity to the treatment.
Herein, a new solid chelating acid is presented, which eliminates many problems typically associated with HCl treatments. This solid acid, when introduced before or in conjunction with an HCl treatment, creates an acid-insoluble filter cake, thus preventing NWB spending. In addition, corrosion testing revealed the solid chelant displays corrosion characteristics similar to aminopolycarboxylic acids and phosphonates, altering the corrosion effects of the HCl acid with tubulars and downhole equipment.
Testing with the solid acid revealed that it can easily be suspended in a gelled HCl acid for placement before or in conjunction with an HCl treatment and exhibits diversionary properties attributed to the small size of the particle entering the pore throats in high permeable matrices. When applied to acid fracturing techniques, core flow testing demonstrated the cake focuses acid spending in a manner resulting in channel-like asperities, rather than broad dissolution of a fracture face. When this technology was applied to matrix acidizing, testing revealed reduced wormhole channel diameter, thus highlighting the effectiveness toward deep matrix penetration of the reactive acid.
In continuance, the filter cake is easily removed with a neutral or alkaline overflush, therefore negating formation damage. Once the filter cake is removed, it exhibits chelation characteristics, thereby retaining spent acid byproducts in solution. This unique property by itself reduces the propensity for recombination of dissolved ions, which can lead to precipitation and possible formation damage.
Production from deepwater environment often encounter ultra high temperature, pressure (ultra HTHP) and with more exotic fluid compositions. Most scale prediction programs were developed by semiempirically modeling the thermodynamic parameters using experimentally measured mineral solubilities and other chemical properties. However, the experimental data were limited at temperature, pressure, and ionic strength that were clearly below that typically encountered in deepwater production. Therefore, extending the existing thermodynamic models to HTHP applications is of questionable accuracy. Furthermore, the partitioning of H2O, CO2, and H2S in and out of the gas/oil phases during production can have a significant impact on scaling tendency. The authors have published papers on experimental solubility measurements and thermodynamic modeling to extend the solubility data to HTHP condition. The new thermodynamic parameters and a flash calculator that integrate the latest development of Equation of State (EOS) to model the partition of H2O, CO2, and H2S in hydrocarbon/aqueous phases at temperature and pressure have been incorporated into a scale prediction software that is specifically tailored for oil and gas production application.
The objective of this paper is to validate the software's application range with a set of critically evaluated peer-reviewed mineral solubility data for general oilfield produced water and deepwater HTHP application. A total of 73 selected papers and more than 2,500 individual experimental data points were included in this evaluation. Our model has been shown to be applicable to greater than 95% of produced water compositions with SI prediction of better than ±0.03 for halite, ±0.05 for gypsum, ±0.1 for calcite and anhydrite, and ±0.2 for barite at temperature between 32 - 500 °F, and and pressure between 14.7 to 22,000 psia. The newly incorporated flash calculator is capable of predicting how CO2, H2S, and H2O partition in and out of the gas phase during production. The partitioning of CO2, H2S, and H2O between the hydrocarbon and aqueous phases has significantly changed the ion composition and pH and therefore, impacted the scaling tendency of the fluids at the production temperature and pressure. This is a particularly important issue for newer wells with high volumes of gas and low water cuts and for CO2 flooding.
Large-scale seawater injection in two high permeability carbonate reservoirs within a remote onshore field commenced with the onset of oil production in early 2000. Following a recent incremental development plan that included an underlying low permeability (2 millidarcies (md)) reservoir with high calcium content (37,000 mg/L) formation water, it became necessary to examine alternative options to the seawater to avoid calcium sulfate scaling and microbial fouling. Secondary treated sewage effluent (TSE) is abundant from nearby urban treatment plants and presents an attractive option for the high-risk divalent ion formation brine environment.
An initial feasibility study focused on geochemical and microbial compatibility to assess the benefits expected from substituting the use of costly desulfated water
The study confirmed that sampled TSE had a relatively low content of contaminants such as oxygen demanding substances (ODS), heavy metals and dissolved solids with minimal formation damage risk compared to both seawater and field produced water. It also revealed variations of total organic carbon (TOC) in TSE, which may enhance troublesome microbial activities and impact the various systems' operational stages
This paper discusses the laboratory experiments and simulation conducted to assess the impact of injection TSE on microbial growth, in situ scale deposition and the associated formation damage risk. It also provides an insight into the effluent quality threshold required for injection in a reservoir of high divalent-salt connate water.
Zhang, Guoyin (New Mexico Petroleum Recovery Research Center) | Yu, Jianjia (New Mexico Petroleum Recovery Research Center) | Du, Cheng (New Mexico Petroleum Recovery Research Center) | Lee, Robert (New Mexico Petroleum Recovery Research Center)
To address the disadvangates associated with the use of alkali during surfactant flooding, such as reduction of polymer viscosity, formation scaling, corrosion hazards, and emulsion formed by the produced fluids, this study focuses on the formulation of surfactants without alkali for either very low salinity (<10,000 ppm TDS) or very high salinity (>100,000 ppm TDS) surfactant flooding. A series of laboratory tests were conducted to investigate the synergism among anionic, cationic, nonionic and zwitterionic surfactants for EOR purposes based on IFT and phase behavior measurements. All the surfactants used in this study are commercially available and no alkali is added for all cases. The results demonstrate that strong interactions between anionic/cationic and anionic/zwitterionic surfactants make them form highly active aggregates which behave more like nonionic surfactants and exhibit great salt tolerance capability. Ultra-low interfacial tensions (IFTs) with the order of magnitude of 10-3 mN/m are achieved by these mixtures. By adjusting the mixing ratio, they can be tailored easily to reservoirs with different salinities and solid surface charges. The anionic/zwitterionic surfactant mixtures at certain pH show exceptional performance, which are able to form middle microemulsion phase from as low as 0 till up to 180,000 ppm TDS salinity. The study also shows the addition of cosolvents (short chain alcohols) should be thoroughly justified during surfactant formulation because they can improve the surfactant solubility and speed phase coalescence. However, they may adversely afftect the water and oil solubilization capacity.
Yang, Jiang (RIPED, PetroChina & Xi'an Petroleum University) | Liu, Xuan (Xi'an Petroleum University) | Jia, Shuai (Xi'an Petroleum University) | Qin, Wenlong (Xi'an Petroleum University) | Yin, Chengxian (Tubular Goods R&D Center, PetroChina) | Liu, Chen (Southwest Petroleum University)
Corrosion inhibitors are widely used to control corrosion under the sweet and sour environments in oil and gas industries. More effective and environment friendly corrosion inhibitors need to be developed. This paper studies a new gemini imidazoline corrosion inhibitor, which two hydrocarbon chains and two headgroups are linked by a rigid spacer. The gemini imidazoline was synthesized through the reaction of oleic acid with triethylene tetramine at 2:1 molar ratio. The product was characterized by infrared spectroscopy, chromatography and mass spectroscopy. The performance of the gemini imidazoline on inhibition of CO2 corrosion was evaluated by linear polarization resistance in sparged beaker testing. Rotating wheel testing was performed to evaluate the film persistency of the test inhibitors. The results showed that corrosion inhibition of the gemini imidazoline was more effective at lower concentration than that of conventional imidazoline. The gemini imidazoline mixed with fatty acid also showed better film persistency than that of conventional imidazoline. The emulsion tendency of the gemini imidazoline was less than that of conventional imidazoline. The mechanism of the highly effective gemini imidazoline was studied. It showed that gemini imidazoline has much higher surface activity than that of conventional imidazoline. The critical micelle concentration is several times lower than that of conventional imidazoline. Hence, the new gemini imidazoline (GIM) corrosion inhibitor and its mixture give more effective corrosion inhibition at low concentration, which also has less environmental impact.
Keller-Schultz, Carrie (Nalco - Champion, An Ecolab company) | Barron-Aldana, Jesus (Nalco - Champion, An Ecolab company) | Peter, Cruz St. (Nalco - Champion, An Ecolab company) | De Paula, Renato M. (Nalco - Champion, An Ecolab company) | Keasler, Victor V. (Nalco - Champion, An Ecolab company) | Grieme, Linda (Ecolab USA Inc.) | Nguyen, Duc (PepsiCo)
Several issues associated with microorganisms found throughout the petroleum industry include microbial influenced corrosion (MIC), biotic souring, and biofouling. Traditional methods for evaluating biocide efficacy within the petroleum industry have been focused specifically toward the planktonic, or free-floating, microorganisms. The sessile population, or the community of microorganisms contained within the biofilms that adhere to each other on a surface are not adequately assessed. Since microorganisms contained within biofilms can contribute to all three major microbial issues in the oilfield and the complexity of the microbial community effects the chemical treatment strategy, there is an increased importance associated with the ability to develop a representative, mature biofilm in a lab setting in order to evaluate the efficacy of the chemical treatments prior to implementation in the field. Currently, there are a variety of laboratory methods designed to grow biofilms. However, these methods suffer from many drawbacks. This includes large quantity of fluid required to achieve a once-through system, the number of samples available to test, and the reproducibility of the biofilm growth itself. The purpose of this paper will be to introduce a novel method that will allow for an increased scalability, reproducibility, and utility in laboratory biofilm studies. This knowledge will help in a better understanding of biofilms and facilitate the development of treatment strategies targeting biofilms.
The interactions of bitumen with clays are known to cause asphaltene deposition. However, the role of clay type on this interaction remains uncertain. We study this interaction for two clay types at steam temperature. Two Steam Assisted Gravity Drainage (SAGD) experiments at identical experimental conditions are conducted. The reservoir rock for the first experiment (SAGD1) is prepared with sand (85 wt%) and kaolinite (15 wt%) mixture and the second experiment (SAGD2) with sand (85 wt%), kaolinite (13.5 wt%), and illite (1.5 wt%). The effectiveness of the steam chamber growth does not change with the clay type, however, 15 wt% less oil is recovered with SAGD2. The possible reasons are investigated through the contact angle, particle size, zeta potential, and interfacial tension measurements on produced oil, produced water, and spent rock. The spent rock samples are analyzed by X-Ray Diffraction (XRD) and Scanning Electron Microscope (SEM) analyses. The contact angle measurements on the spent rock sample display the higher oil-wetness for SAGD2 than SAGD1. However, the water-wetness of illite is known to be higher than kaolinite. This unexpected result is explained by the interaction of illite and the asphaltenes from SAGD2. The asphaltenes both from produced oil and residual oil separated and qualitative analyses are conducted with Fourier Transform InfraRed (FTIR). FTIR results confirm the presence of clay in the produced oil asphaltenes of SAGD2. The particle size measurements along with SEM images on postmortem samples reveal that illite containing clay exhibits cementation behavior at steam temperature, hence, reduces the permeability of the system. According to the experimental results, we developed hypotheses to understand the bitumen-illite and bitumen-kaolinite interactions for SAGD. Due to the high water-wetness of illite, illite particles first interact with steam. This interaction results in cementation and forms illite lumps with sand. And then, illite lumps continue to interact more vigorously with the polar molecules (water, asphaltenes, and resins). Clay migration and production occur in both clay types, however, while kaolinite is produced in the water phase, illite containing clay due to its interaction with asphaltenes produced in the oil phase.
Panchalingam, Vaithilingam (Baker Hughes, Inc.) | Liu, Zhengwei (Baker Hughes, Inc.) | Rivers, Gordon (Baker Hughes, Inc.) | Garza, Tim (Baker Hughes, Inc.) | Cook, Stuart (Baker Hughes, Inc.) | Stead, Paul (Baker Hughes, Inc.) | McEachern, Heather (Baker Hughes, Inc.) | Frostman, Lynn (Baker Hughes, Inc.)
Low dosage hydrate inhibitors (LDHIs) have been used as alternatives to thermodynamic inhibitors such as methanol or mono ethylene glycol (MEG) to control hydrate problems. The major advantage of using LDHIs is that they control with a much lower dosage, typically 1 to 3vol% (based on water production volume), thus lowering storage requirements and logistical challenges, compared to much higher volumes required for methanol or MEG. Anti-agglomerants (AAs), as one type of LDHI, allow hydrates to form but inhibit growth and agglomeration of hydrate crystals. Some very effective AAs exhibit a pitting corrosion risk for offshore umbilical chemical delivery systems under certain conditions. An electrochemical method of cyclic potentiodynamic polarization (CPP), a modified ASTM G-61 method at ambient temperature, and immersion testing using a modified ASTM G-31 method at elevated temperatures were used to evaluate pitting tendencies of AA formulations containing corrosion inhibitors on stainless and duplex steels. Initially, these corrosion inhibitors were effective in controlling pitting corrosion in stainless steel only as shown by CPP and immersion testing. After modifying the manufacturing process and adjusting solvent systems, the selected corrosion inhibitors have been shown to be effective for both stainless and duplex steels. Hydrate performance testing showed no performance compromise with the presence of corrosion inhibitors within the AA formulation or from changing the solvent system. Mitigation of pitting tendency was also confirmed by immersion testing at elevated temperatures.
In many areas water used for steam flood injection has varied concentrations of dissolved silicon (Si), which can form silica scale, reducing thermal efficiency, and lowering steam quality. Scale inhibitors are typically used today, but removal of Si may be a more cost-efficient process to reuse the water, especially in areas with limited fresh water availability. Removing Si in the water treatment plant before steam generation can lead to higher quality steam at lower costs and result in better production.
Typical chemical precipitation methods have been reported for Si removal by adding different coagulant compounds that contain elements such as aluminum (Al), iron (Fe) or molybdenum (Mo). In general, the chemical precipitation method needs high volumes of coagulants and generates considerable amounts of sludge, and may also input extra compounds or ions into the treated water. Electrocoagulation (EC) has been claimed for Si removal, but low conductivity water (or low concentration of total dissolved salt (TDS)), as seen in steam injection systems, is not well-matched to traditional EC systems.
In this paper, a uniquely designed electrocoagulation (EC) system with non-sacrificial electrodes and sacrificial material was tested for Si removal from steam injection water. This EC system has been shown to be highly flexible and efficient for treating waters with TDS levels from 3,000 to over 300,000 mg/L, especially for Si, Fe, and suspended solid removal. The water in this case was hot (180°F), low TDS (<6,000mg/L), and had 60 to 80 mg/L of Si. Both laboratory scale testing and pilot field trial showed efficient Si removal from the water to less than 2 mg/L at varied temperatures. Significant hardness removal was also achieved during the same process. Compared with chemical precipitation methods, this unique EC system used fewer chemicals, generated less sludge, and provided a higher quality of effluent water.