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Collaborating Authors
Saskatchewan
Abstract Viscoelastic surfactants (VES) are used in upstream oil and gas applications, particularly hydraulic fracturing and matrix acidizing. A description of surfactant types is introduced along with a theoretical description of how they assemble into micelles, what sizes and shapes of micelles can be formed under different conditions, and finally how specific structures can lead to bulk viscoelastic solution properties. This theoretical discussion leads into a description of the specific VES systems that have been used over the last twenty years or so in improved oil recovery for upstream applications. VES-based fluids have been used most extensively for hydraulic fracturing. They are preferred over conventional polymer-based fracturing fluid systems because they are essentially solids-free systems which have demonstrated less damage to the reservoir rock formation. Important advancements in VES have been made by introducing “pseudo-crosslinking agents” such as nanoparticles to enhance the viscosity. Fracturing fluid systems based on VES have also been improved recently by developing internal breakers to lower their viscosity in order to flow back the well. The flexibility of VES-based fluids has been demonstrated by their application as foamed fluids as well as their incorporation with brine systems such as produced water. A second key area that has benefited from VES-based systems is matrix acidizing carbonated-based reservoirs. The viscosity of these VES-based fluids is mostly controlled by pH where, at low pH (low viscosity), the acid system flows easily and invades pore spaces in the formation. During acidizing, the acid is spent, and the pH and viscosity increase. Because the spent acid has higher viscosity, fresh acid is diverted to low permeability un-contacted zones and penetrates the rocks to form wormholes. A number of experimental studies and field applications to these effects have been performed and will be described here. In order for VES-based fluids to play a more prominent role in the field, inherent limitations such as cost, applicable temperature range, and leak-off characteristics will need to continue to be addressed. If we can efficiently and economically overcome these issues, VES-based fluids offer the industry an excellent clean, non-damaging alternative to conventional polymer-based fluids.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > Canada (0.68)
- Asia > Middle East > Saudi Arabia (0.68)
- Geology > Rock Type > Sedimentary Rock (0.67)
- Geology > Mineral > Halide (0.46)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.40)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- South America > Argentina > Chubut > Golfo San Jorge Basin > El Tordillo Field (0.99)
- North America > United States > Wyoming > Waltman Field (0.99)
- (14 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- (6 more...)
Abstract The impact of electrolytes contained in sea water and 20 wt.% NaCl solution on three chemically different fluid loss additives was investigated. As fluid loss additives, a synthetic copolymer of 2-acrylamido-tertiary-butyl sulfonic acid (ATBS) and N, N-dimethyl acrylamide (NNDMA) and two graft copolymers, one based on humic acid-{ATBS-co-NNDMA-co-acrylic acid} and another based on lignite-{ATBS-co-NNDMA} were studied. Rheology and fluid loss of cement slurries prepared from fresh water, synthetic sea water and 20 % NaCl were measured at 27 °C and 150 °C. Significant differences were found between the admixtures with respect to their salt tolerance. Both graft copolymers are particularly tolerant to NaCl, but highly sensitive to sea water. Whereas the ATBS-co-NNDMA polymer performs well in sea water while it fails at higher NaCl contents. A mechanistic investigation revealed that higher NaCl concentrations decrease adsorption of the ATBS-co-NNDMA copolymer on cement and thus reduce its plugging effect on the pores of the cement filter cake. Whereas, sensitivity of the two graft copolymers towards sea water is caused by the presence of Mg. In the highly alkaline pore solution of cement this cation is precipitated as voluminous Mg(OH)2 which can entrap and thus remove a significant amount of the graft copolymer. Such co-precipitation effect does not occur with ATBS-co-NNDMA. The pronounced effect of Mg is extremely surprising, because of its low concentration in sea water (~ 1.3 g/L only). The study suggests that in order to detect potential incompatibilities of oil well cement additives with salts, their behavior towards individual electrolytes instead of fully formulated salt brines should be tested. Such insight can prevent failures in the field and allows developing novel additives possessing enhanced salt tolerance.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- North America > Canada > Saskatchewan > Williston Basin (0.99)
- North America > Canada > Manitoba > Williston Basin (0.99)
- North America > Canada > Alberta > Williston Basin (0.99)
Abstract Viscoelastic surfactant (VES) fracture fluids were developed as a nondamaging alternative to conventional polymer-based fluids. However, the viscosity performance of typical VES fluids is dramatically reduced at high temperature. Therefore, these fluids are typically limited to treat relatively low-temperature formations unless foamed with nitrogen or carbon dioxide. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, combination of rotational and oscillatory measurements to determine the fluid viscous and elastic properties can better predict whether the fluid can be applied successfully in the field. The present study was conducted to introduce a new Gemini VES system that can gel and maintain useful viscosity up to 275°F, which can provide additional downhole benefits. Dynamic and static proppant settling tests were conducted using a high-pressure/high-temperature visualization cell to confirm the effect of elastic properties of this fluid on proppant settling. Finally, proppant settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations. Experimental results show that the surfactant gel behaved as an elastic material (elastic regime), where the elastic modulus (G') was dominant over the viscous modulus (G”) during the tested range of frequency. This behavior gives perfect proppant transport properties. At temperature less than 225°F, Values of G′ were independent of the frequency and/or shear rate values, while G” increased with increasing frequency and/or shear rate. At higher temperature, both G′ and G” increased with increasing frequency and/or shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The addition of an internal liquid breaker increases the viscous regime with time and temperature. When elastic regime dominates, 100% proppant suspension was confirmed for at least two hours at static and dynamic conditions and temperatures in the range of 75 to 250°F.
- North America > United States > Texas (0.29)
- North America > Canada > Alberta (0.28)
- North America > United States > Louisiana (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- North America > United States > Wyoming > Greater Green River Basin > Wamsutter Basin > Wamsutter Field (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
Abstract Early viscoelastic surfactant fluid systems provided a non-damaging, non-polymer viscous fluid option for many tight gas fracturing applications. These fluids were operationally simplistic with only a few additives. However, their rheological properties limit their use to about 140°F as a single fluid. For applications to about 250°F, foaming the fluids with CO or N, usually 65 to 75 quality, can achieve stability with adequate viscosity, but this increases costs as well as operational and logistical complication. In addition, these fluids provide minimal friction reduction because at high shear they tend to behave more like water. A new thickening system extends the temperature range of traditional viscoelastic surfactant (VES) fluids and provides additional downhole benefits. Based on a low-molecular-weight associative polymer, the thickener forms an associative gel with surfactants at elevated temperature. The polymer and surfactants can be considered environmentally preferred. The system uses only three or four additives, compared to nine or ten for conventional systems. The footprint for field operations is considerably reduced, as hydration units and chemical additive units are not necessary. In rheology testing, the system achieves a good structure with viscosity. The time required to gel with temperature can be accelerated or delayed chemically. Regain conductivity tests indicate performance is similar to that of VES fluids alone. The system also has beneficial traits for clay control, friction reduction, water-wetting and post-frac fluid recovery. If foamed, the system may provide stability at even higher temperatures. This paper will present the chemistry and results of laboratory testing of this new and unique fluid system. The system should have applications in areas requiring excellent regain conductivities, such as unconventional formations.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.29)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.70)
Abstract Reservoir souring refers to the onset of hydrogen sulfide production during waterflooding. Besides health and safety issues, HS content reduces the value of the produced hydrocarbon. Nitrate injection is an effective method to prevent the formation of HS. Designing this process requires the modeling of a complicated set of biogeochemical reactions involved in the production of HS and its inhibition. This paper describes the modeling and simulation of biological reactions associated with the injection of nitrate to inhibit reservoir souring. The model is implemented in a general purpose adaptive reservoir simulator (GPAS). To the best of our knowledge, GPAS is the first field-scale reservoir simulator that models reservoir souring treatment. The basic mechanism in the biologically mediated generation of HS is the reaction between sulfate in the injection water and fatty acids in the formation water in the presence of sulfate-reducing bacteria (SRB). There are proposed mechanisms that describe the effect of nitrate injection on souring remediation. Depending on the circumstances, more than one mechanism may occur at the same time. These mechanisms include the inhibitory effect of nitrite on sulfate reduction, the competition between sulfate-reducing bacteria and nitrate-reducing bacteria (NRB), and the stimulation of nitrate-reducing sulfide-oxidizing bacteria (NR-SOB). For each mechanism, we specify the biological species and chemical components involved, and determine the role of each component in the biological reaction. For every biological reaction, a set of ordinary differential equations along with differential equations for the transport of chemical and biological species are solved. The results of reported experiments in the literature are used to find the input parameters for field-scale simulations. This reservoir simulator can then predict the onset of reservoir souring and the effectiveness of nitrate injection and helps the design of the process. The comprehensive modeling accounts for variation in biological system characteristics and reservoir conditions that affect the production and remediation of hydrogen sulfide.
- North America > United States > Texas (0.94)
- Europe (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.55)
- North America > Canada > Saskatchewan > Williston Basin > Coleville Field (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5504/16 > Skjold Field > Zechstein Formation (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OML 118 > Bonga Field (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability (1.00)
Abstract This paper concerns the development and implementation of a replacement chemistry for 2-butoxyethanol used in fracturing. The new product was synthesized to provide mutual solvency, wettability modification and clay swelling inhibition. Recently, 2-butoxyethanol has come under scrutiny in North America (e.g. prompting Environment and Health Canada to add it to Schedule 1 of the Canadian Environmental Protection Act). Precautions need to be taken when working with 2-butoxyethanol due to toxicity concerns. Exposure to high levels has led to reported nose and eye irritation, headaches and vomiting. Introduction of an alternate product has had a profound effect on the stimulation market in Canada. So far, 400,000 kg of the alternative product has replaced an estimated annual usage total of 3 to 4 million kg of 2- butoxyethanol. The new product also has had successful applications in the US, Latin America and Europe. There has been a significant environmental impact already realized through the use of this alternative product, and there is even greater unrealized potential. Additionally, as a non-regulated product for use and handling, the safety and material handling implications are greatly improved. This paper details the chemistry of the replacement product, as well as environmental information to support the use of this product as a benign replacement for 2-butoxyethanol. An in-depth description of the laboratory testing used to identify, evaluate and select the appropriate treatment parameters also is given. The paper concludes with two case histories from northeast Alberta where this product was successfully used as part of a fracture treatment for long, horizontal, multi-zone shale gas plays. Furthermore comparisons are made using 2-butoxyethanol and no mutual solvent chemistry in a fracture treatment. This data shows the clear benefit of using this new chemistry.
- North America > United States > Texas (0.94)
- North America > Canada > British Columbia (0.70)
- North America > Canada > Alberta (0.68)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (4 more...)
Abstract North Dakota Bakken oil recovery has increased nearly 100 fold over the last five years, driven by technological advancements in hydraulic fracturing and completion design. For one North Dakota operator with 150 Bakken-producing wells, 22 of the wells have experienced at least one event of severe calcium carbonate scaling in the pump and production tubing, leading to well failure. Bakken wells are completed to a vertical depth of approximately 10,000 ft with horizontal laterals up to 10,000 ft and produced via multi-zone hydraulic fracturing. The operator initially conducted a typical scale prediction study in order to reduce well failures and maintain oil production. However, the scale prediction study was challenging to perform for these Bakken wells due to the variability of the composition of the produced water. Attention then turned to the tracking and analysis of historic field conditions. A ‘post-mortem’ of data collected from all failed wells due to scale was conducted, considering the failure type, date, type of hydraulic fracturing procedure, pump intake pressure, scale inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure. Results showed that 82 percent of the wells failed during early production (defined as less than 20,000 barrels of water produced and two years production since first oil), after which failures became increasingly rare. This correlated with transient alkalinity spikes in the water analyses attributed to fracturing fluid flowback during this critical period. Simulated blending of fracturing and formation waters demonstrated that this was the most important period to maintain high scale inhibitor residuals due to high deposition potentials. This paper discusses the various field and laboratory studies conducted in an effort to understand the problem, results obtained and implications. Also discussed is the evaluation of two scale inhibitors before and after laboratory aging in simulated fracturing fluids.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.80)
Abstract Nitrate addition to injection water has been used to control the development of reservoir souring through microbial production of hydrogen sulfide particularly in seawater floods offshore. Current interest is in the application of this technology to produced water recycle injection (PWRI) systems in onshore fields. Long term field observations and analyses for PWRI operations in both high and low temperature oil reservoirs have provided insight into issues and potential challenges that can arise in the application of nitrate as a control treatment for souring. This paper will describe the rudiments of a trouble shooting scheme that is being developed to assist in the optimization of field programs. 1.0 Introduction Nitrate addition has long been used to control odours due to microbial sulfide production by anaerobic sulfate reducing bacteria (SRB) in natural environments. Recognition that this same technology could be used to manage the microbial production of sulfide from oil degradation under anaerobic conditions (Jack et al., 1985, Jenneman et al., 1986) led to the development of practical schemes for oilfield application, the best known of which are in seawater floods offshore in the North Sea (Granli and Thoresen, 2009; Sunde and Torsvik, 2005). In 2007, a Natural Sciences and Engineering Research Council Industrial Research Chair in Petroleum Microbiology was established at the University of Calgary with the optimal control of microbial souring as one of its primary objectives. Earlier work had pioneered the use of nitrate in onshore produced water recycle injection (PWRI) systems with a field test in the Western Canadian Sedimentary Basin at the Coleville field in Saskatchewan (Jenneman et al., 1997; Telang et al., 1997). This paper provides a summary of some of the issues and potential challenges that have come to light in field operations currently being monitored in the Research Chair program. The addition of nitrate can effectively suppress sulfide production in situ in a PWRI waterflood operation. Figure 1 shows the successful reduction of dissolved sulfide in produced fluids from a production well receiving nitrate treated water from an adjacent injection well. The virtual elimination of sulfide in aqueous solution coincides with the breakthrough of nitrate at the producer along with derivative nitrite in response to a high concentration batch application of nitrate at the associated injector (Arensdorf et al., 2009). The challenge is to design field applications to achieve and sustain this result in the most cost effective manner possible across entire oil fields. 2.0 Statement of Theory and Definition of Terms The mechanism for control of microbial souring by nitrate addition has been discussed in detail elsewhere (Voordouw, 2008). It involves a shift in the net metabolic activity of the mixed microbial communities responsible for sulfide formation. As outlined in Figure 2, addition of nitrate promotes the activity of heterotrophic nitrate reducing bacteria (hNRB) that can compete with SRB responsible for sulfide formation. In the scheme shown, both groups of microorganisms are competing for organics to support their metabolism. A second mode of suppression of sulfide production as well as elimination of sulfide arises from the promotion of nitrate reducing sulfide oxiding organisms (NR-SOB) in the community. These organisms are able to couple nitrate reduction directly to sulfide oxidation. These nitrate reducing organisms release nitrite as a primary reduction product. Nitrite specifically inhibits sulfide formation in SRB and can be a powerful agent of souring control. The challenge in managing microbial souring in PWRI systems is to supply nitrate in a way that cost effectively promotes sufficient activity by hNRB and NR-SOB in microbial communities where SRB are present and active underground. This paper identifies factors and processes that must be considered in addressing this challenge.
- North America > Canada > Saskatchewan (0.88)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.25)
- North America > Canada > Saskatchewan > Williston Basin > Coleville Field (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Microbial methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- (2 more...)
Abstract Asphaltene precipitation and deposition models were established and verified by typical experimental data. These models, the porosity and permeability reduction models, and the asphaltene mass balance equation were incorporated into a three-dimensional, three-phase black-oil simulator. Two typical cases involving asphaltene deposition in petroleum reservoirs associated with vertical and horizontal wells were investigated using the simulator. During the three-year period of production, the productivity index declined more than 50 % for both the vertical and horizontal wells. The pattern of asphaltene deposition in the reservoir with a horizontal well was found to be different from that in the reservoir with a vertical well. Introduction The existence state of asphaltene in crude oil is different than in solvent [1]. The crude oil containing asphaltene is a real solution, but asphaltene forms aggregation in solvent [1]. The process of asphaltene precipitation in hydrocarbon miscible flooding is also different from that due to pressure depletion during primary oil recovery [1]. The detailed review of the existence state of asphaltene in crude oil, and the precipitation and deposition of asphaltene in petroleum reservoirs is given in Table 1–7 by Wang [1]. In this paper, an asphaltene precipitation model is developed and verified by a typical experimental data. Then, a porous media deposition model for asphaltene is established and applied to six sets of experimental data. Finally, the precipitation and deposition models for asphaltene as well as other auxiliary models are incorporated into a three-dimensional, three-phase black-oil simulator. Two typical cases are evaluated with the simulator and representative results are reported. Asphaltene Precipitation Model The polymer solution theory represents the existence state of asphaltene in crude oil more accurately than the colloidal theory [1]. Hirschberg et al. [11] first applied the polymer solution theory to simulate the asphaltene precipitation problem. By combining the Flory-Huggins theory for polymer solution and Hildebrand solubility concept, Hirschberg et al. [11] obtained the following equation:Equation (1) where, fA is the volume fraction of asphaltene dissolved in the crude oil. VA is the molar volume of asphaltene, assumed constant. VL is the molar volume of liquid phase, calculated with the modified Benedict-Webb-Rubin state equation in the Hirschberg et al. model. R is the universal gas constant and T is the absolute temperature. dL is the solubility parameter of asphaltene, given as :Equation (2) where h is a specific constant for each oil and dL is the solubility parameter of the liquid phase defined by [49]:Equation (3) where ?Uvaporization is the internal energy change during the vaporization of a unit mole liquid.
- South America (0.68)
- North America > United States > Texas > Harris County > Houston (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
- North America > United States > California > Los Angeles Basin (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.89)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.89)
- (4 more...)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)