A Novel Foaming Agent for Hydraulic Fracturing: Laboratory Investigation and Field Usage

Stability study of aqueous foams under high-temperature and high-pressure conditions relevant to Enhanced Geothermal Systems (EGS)

Guar and hydroxypropyl guar are used to prepare high pH borate gels at various concentrations up to 45 lb/1000 gals. Oxidizers are usually used to degrade the gel after the fracturing treatment. This study was conducted to assess the effect of polymer type and loading on gel degradation; and determine other parameters that may affect the time needed to clean-up fractured wells. Guar gum and HPG were used prepare the gel. Sodium bromate and chlorous acid were used as breakers. Gel degradation was examined at typical field conditions. The apparent viscosity of various borate gels was measured as a function of breaker type and polymer loading. Gel degradation was followed in a high temperature/high pressure see-through cell. Viscosity measurements indicated that sodium bromate and chlorous acid were able to degrade high pH borate gels at different polymer loadings. All guar-based gels produced a residue after reacting with the breaker. The amount of residue was measured after heating the sample in the see-through cell at 140°C and 300 psi after four hours. The results indicated that the guar gum produced higher amount of residue compared to gel prepared with HPG polymer. Surface tension measurements indicated that the type of oxidizers did not affect surface tension of gel filtrate. Suitable nonionic surfactants were able to reduce surface tension of gel filtrate. Surface tension of gel filtrate decreased with increasing temperature. Introduction Fracturing fluid is one of the most important components in hydraulic fracturing treatments.1 The fluid is used to create fracture and transport proppant down the created fracture. Guar and its derivatives; HPG (hydroxypropyl guar), and CMHPG (carboxymethyhydroxypropyl guar), are the most commonly used polymers to prepare water-based fracturing fluid.2 High viscosity is generated by crosslinking the polymer molecules with a crosslinker (B(III), Ti(IV), or Zr(IV)).1 Borate gels have been used in the oil industry as fracture fluids and zone isolation.3 Guar gum and HPG are cross-linked with monoborate ions B(OH)4-. The source of this ion is boric acid, borax, or organoborate salts. Analysis of well flow back samples following fracture treatments highlighted the presence of very viscous fluids and gel fragments. Also, the time needed to clean the fractured wells was too long. These trends indicated that the gels used in these treatments did not break completely. The objectives of this paper are to:evaluate the performance of two oxidizers at typical field conditions andstudy the effect of changing the polymer loading and polymer type on the rate of degradation of these gels,determine the effect of oxidizer type and temperature on the surface tension of gel filtrate. Background Guar gum is a naturally occurring polysaccharide that is used extensively as a water-based viscosifier. Guar is a linear polymer with a backbone composed of mannose units connected by ß-1,4 acetal linkages. This backbone has single unit branches of galactose connected by a-1,6 acetal linkages.4 Boric acid or borate salts have been used as a source of monoborate ions. It has been suggested that the cross-linking reaction occurred due to either the formation of borate esters,5 hydrogen bonding,6 or p-bond overlap.7

Carbon dioxide and nitrogen have both proven to be useful aids in will stimulation. Laboratory data are presented showing the effect of carbon dioxide on foaming agents, corrosion, reaction rate of hydrochloric acid, fluid-loss additives and clay swelling. Carbon dioxide is generally beneficial for all of these except the fluid-loss additives. The corrosion rate of carbonated water is very low compared to inhibited hydrochloric acid. A chart of the viscosity of carbon dioxide is presented. If is estimated that carbon dioxide can reduce friction loss of oil-base fluids by 29 to 60 per cent. Individual field results and conclusions from other summaries are presented. Both nitrogen and carbon dioxide are effective in removal of stimulation fluids. Carbon dioxide has proven useful in removing water or emulsion blocks. Introduction The use of nitrogen and carbon dioxide in well stimulations has grown rapidly in the past two years. The uses and advantages of these gases have been described previously for well stimulation, testing and cementing programs. Because of the differences in physical and chemical properties between nitrogen and carbon dioxide, one gas is usually better suited than the other for a specific application. Generally speaking, nitrogen is superior in low injection rate applications and when precise volume control is critical. Carbon dioxide, on the other hand, is better adaptable to high rate fracturing and acid treatments. Gases were introduced to the oil and gas industry primarily as an aid to recovery of stimulation fluids. This application still accounts for the major usage of nitrogen and carbon dioxide. Special applications, however, which utilize specific properties of the gases, are being discovered continually. The development of these methods is opening the door to better controls over well performance. Effect of a Foaming Additive with Nitrogen and Carbon Dioxide By the nature of the solubility-pressure relationship of carbon dioxide, an induced solution-gas-drive mechanism is created when the pressure is lowered and the gas comes out of solution. To demonstrate this effect the apparatus shown in Fig. 1 was constructed. The 160-cc cell was filled to 100 cc with the fluid to be tested, a gas pressure (nitrogen or CO2) of about 800 psi was applied and allowed to come to equilibrium. The valve was then opened and the amount of liquid carried over was measured in a graduated cylinder. These tests were also conducted using various amounts of foaming additive to see if the additive would enhance the recovery. The results of these tests are given in Table 1. As expected, the recovery of fluids was substantially greater when using CO2 than when using nitrogen. For example, at 80F the recovery with CO2, and no foaming additive was 40 per cent, while with nitrogen it was essentially zero. The addition of the foaming agent increased the recovery substantially. With CO2 the recovery increased from 40 per cent to 70 per cent when 0.2 per cent foaming additive was used.

High temperature rheology of carbon dioxide foam fracturing fluids has been developed in the laboratory and successfully applied to improve the design of foam fracturing treatments of tight gas sands. In the laboratory phase of the project, carbon dioxide foam properties were measured to 250°F (121°C) in a high temperature, high pressure pipe viscometer. The effects of foamer type and concentration on high temperature carbon dioxide foam rheology were determined. It was found that, above a certain level, further increases in foamer concentration provide little corresponding increase in foam stability or rheology. Carbon dioxide foam stability can be improved by the use of higher concentrations of gelling agent. Test data indicates that higher concentrations of foamer and gellant are required to produce stable carbon dioxide foams, as compared to nitrogen foams. It was found that rheological data generated for nitrogen foams will not be sufficient to describe the same system when pumped as a carbon dioxide foam, as had been previously assumed. Historically, foam fracturing design and fluid composition (gellant and foamer) have been based on rules of thumb and common area practice. The laboratory generated foam rheology and stability data were used to modify fracturing design and fluid composition. These design changes have resulted in more successful carbon dioxide foam stimulation treatments and have drastically reduced screen-outs. Examples of successful treatments utilizing the new design data will be compared and contrasted with historic treatments in several tight gas sands.

Computerized monitoring of hydraulic fracturing treatments has been an accepted practice for several years. Not only can a continuous record of the treatment parameters be made, but the real-time bottomhole treating pressure can be determined without the use of a reference string or bottomhole pressure tool. However, to calculate the bottomhole treating pressure, the friction pressure of the fluid or slurry must be determined. For conventional, incompressible oil and water-based fluids friction pressure is a straightforward calculation since rate and proppant concentration are the main considerations. The friction pressure for foam fracturing fluids requires a more complex solution. A computer van was used to monitor carbon dioxide and nitrogen foam treatments incorporating a reference string or bottomhole pressure tool. The following parameters involved in the calculation of bottomhole treating pressure were examined in this study: injection rate, addition of proppant, effect of proppant on slurry friction pressure and foam hydrostatic head pressure. This paper presents a technique which allows the bottomhole treating pressure to be calculated without the use of a reference string or bottomhole pressure tool. The calculation of bottomhole treating pressure for a foam treatment incorporates a technique to correct the hydrostatic head pressure of carbon dioxide and nitrogen foams. In addition, the different effects of proppant addition on friction pressure between nitrogen and carbon dioxide generated foams are discussed.

Previous studies(1-4) described the theory and application of CO 2 miscible hydrocarbon fracturing fluids for gas well stimulation. These fluids are ideally suited to gas reservoirs susceptible to phase trapping resulting from high capillary pressures when water-based fluids are used. Gas reservoirs particularly prone to phase trapping are those with in situ permeability less than 0.1 mD, those with initial water saturations less than what would be expected from normal capillary equilibrium (subnormally water saturated) and those that are under pressured. Such reservoirs represent a growing proportion of the market. This, combined with increased gas prices, creates a strong need for an optimized gas well fracturing fluid system. Hydrocarbon-based fracturing fluids present an ideal solution to phase trapping concerns associated with water-based fluids provided the hydrocarbon fluid can be effectively and quickly removed from the formation after the fracturing treatment. This paper investigates in more depth what constitutes an ideal hydrocarbon-base oil for this application. This involves consideration of many factors including cleanup mechanisms, safety, cost and capability to be gelled and broken. In order to meaningfully evaluate fluid clean up, regained core permeability evaluations must be conducted by accurately duplicating downhole conditions. This paper presents testing methodologies designed to achieve this goal. To illustrate the need for these methodologies, the applicable phase behaviour and fluid displacement mechanisms by which these fluid systems operate are discussed. Topics covered will include: Methane drive fluid recovery mechanism involving the use of CO 2 with hydrocarbons and resulting effect on interfacial tension (IFT). • Secondary recovery mechanism based on vapour pressure of light hydrocarbons resulting in their being produced back in the gas phase with methane. • Application of these concepts to address phase trapping in low-permeability gas reservoirs and how these effects are accentuated in formations that may be subnormally water-saturated, have low reservoir pressure or have low permeability. • The need to simulate downhole conditions accurately to properly represent the recovery mechanisms. This includes duplication of temperature, pressure and fluid-loss mechanisms. Duplicating leakoff is the key to representative duplication of phenomena at the fracture face. • Compare nitrogen to methane for reference and fluid recoveries and discuss why it is necessary to use methane to obtain proper simulation and modelling of the actual field performance of the fracture fluids. To illustrate fluid performance and demonstrate test methodologies, results of a regain permeability evaluation conducted with the optimum fluid and test methodologies discussed will be presented. It will be shown that in a formation known to be highly sensitive to water-based fluid retention (phase trapping), 100% regain permeability can be achieved at a minimal 140 kPa of applied drawdown pressure.

Results from a series of laboratory hydrofracture tests, in which different fracture fluids, fracture fluid injection rates, confining pressures, and test specimen mechanical and fluid transport properties were used, are presented and discussed. Fracture fluids included various simple linear viscous (Newtonian) fluids and different combinations of three types of commercial fracture fluids: linear gels, cross-linked gels, and combinations of gels with suspended solids. Systematic variations in the behavior of fracture initiation pressures, and fracture fluid pressures during stages of stable fracture propagation, are observed to depend on fluid flow resistance, leak-off rate, and fracture fluid rheology. Post-test inspections of hydrofracture surfaces indicate the presence of a dry zone near the fracture tip. The effective hydrofracture toughness parameters determined from the tests with fracture fluid gels are substantially higher than the normal Mode-I toughness values, determined for the same material. The behavior is interpreted to be the consequence of a build-up of solids at the fracture tip, from dehydration of fracture fluids containing gels and/or solids.

The paper describes a new approach used to select fracture fluid systems by applying fuzzy logic for fracture treatments. Based on the given formation information, the system first determines base fluid, viscosifying method, and energization method. Secondly, the system chooses the 3 to 5 best combinations of the possible fluids. Then, the system determines polymer type and loading, crosslinker, gas type if necessary, and other additives for the fluid systems. At the same time, the system also checks the compatibility of the fluid and additives with formation fluids and composition. The fuzzy logic system described in this paper, which is consisted of several fuzzy logic evaluators, can be applied to study, evaluate, and determine the best fluid systems to stimulate oil and gas production or water injectivity in wells. The approach can be extended to the solution of many other similar problems associated with drilling, completing, and working over wells. Introduction Hydraulic fracturing is one of major methods to increase reservoir production. The success or failure of a fracture treatment heavily depends on the fracturing fluids and additives used in the treatment. Choosing the correct fluid and additives is extremely important to ensure that the formation is not damaged, proppant is placed in formation as designed, and the fluid breaks and cleans up properly. Fracturing fluids are used to create fractures and to transport proppant down the tubular goods, through the perforations, and deep into the fracture. To pump a successful fracture treatment, an ideal fracturing fluid should have the following characteristics.–The fluid should be compatible with the formation and the reservoir fluids.–The fluid should be able to maintain sufficient viscosity at reservoir temperature, so it can suspend proppant and transport it deep into the fracture.–The fluid should be capable of developing the necessary fracture width to accept proppants or to allow deep acid penetration.–The fluid should have low fluid loss properties or high fluid efficiency.–The fluid should be easy to remove from the formation and have minimal damaging effects on both the proppant and the formation.–The fluid should be easily pumped down the wellbore and exhibit minimal friction pressure losses in both the pipe and the fracture.–The fluid should be easy to prepare and safe to use.–The fluid should be low cost. Currently available fracturing fluids seldom satisfy all of the above requirements. Of these, however, the most important requirements that we have to consider when selecting a fracturing fluid are (1) the ability to maintain sufficient viscosity at reservoir temperature and (2) compatibility with the formation and reservoir fluids. Fracture fluids can be divided into four groups:water-based fluids,oil-based fluids,foam-based fluids, andalcohol-based fluids. Table 1 describes these fluid types, and the conditions under which they are most often used. The selection of optimal fracturing fluids for a formation is based on consideration of the following factors: formation pressure, water sensitivity of the formation, formation temperature, permeability, and the fracture half-length to be created. Laboratory testing and field experience provide important information that must be considered when choosing a fracture fluid. These decisions are crucial to the success or failure of the stimulation treatment, and require comprehensive data sets, knowledge, and experience. P. 293

High-quality supercritical CO2 (sCO2) foam as a fracturing fluid is considered ideal for fracturing shale gas reservoirs. The apparent viscosity of the fracturing fluid holds an important role and governs the efficiency of the fracturing process. In this study, the viscosity of sCO2 foam and its empirical correlations are presented as a function of temperature, pressure, and shear rate. A series of experiments were performed to investigate the effect of temperature, pressure, and shear rate on the apparent viscosity of sCO2 foam generated by a widely used mixed surfactant system. An advanced high pressure, high temperature (HPHT) foam rheometer was used to measure the apparent viscosity of the foam over a wide range of reservoir temperatures (40–120 °C), pressures (1000–2500 psi), and shear rates (10–500 s−1). A well-known power law model was modified to accommodate the individual and combined effect of temperature, pressure, and shear rate on the apparent viscosity of the foam. Flow indices of the power law were found to be a function of temperature, pressure, and shear rate. Nonlinear regression was also performed on the foam apparent viscosity data to develop these correlations. The newly developed correlations provide an accurate prediction of the foam’s apparent viscosity under different fracturing conditions. These correlations can be helpful for evaluating foam-fracturing efficiency by incorporating them into a fracturing simulator.

Enhancing stability and odor control of water-based foam for pesticide site restoration using xanthan gum

Trends in hydraulic fracturing over the years have closely followed an increased knowledge or better understanding of what occurs in the formation during a fracturing treatment. As more and more knowledge was gained emphasis shifted from materials to horsepower and high injection rates. Recently the shift has been back to materials and more careful planning and engineering of individual treatments. Improved technology within the past two or three years has led to the development of new, viscous fracturing fluids and more sophisticated computer programs. These developments have greatly improved results of fracturing treatments and have made it possible to successfully stimulate those wells which previously were poor candidates for hydraulic fracturing poor candidates for hydraulic fracturing treatments. The purpose of this paper is to discuss recent developments in fracture fluids and techniques and the technology involved in their use. Case histories are used to show the improvements in economy, efficiency, and increased production results. Introduction Since the introduction Hydraulic fracturing as a stimulation tool in the late 1940's, development trends have closely paralleled each fact learned concerning what actually takes place in a formation during a fracture treatment place in a formation during a fracture treatment In the early days, equipment available was capable of providing injection rates of one to two barrels per minute and screen-outs were common. It was felt that viscous fluids would suspend and transport propping agents better and development emphasis was on fracture fluids. Heavy refined oils became common frac fluids and water-in-oil emulsions, acid-in-oil emulsions, and soap-type oil gels appeared. Next, fluid loss was recognized and fluid loss agents were introduced. It was discovered that in many cases crude oil could be used as a fracture fluid with these new agents and treating economics apparently improved. The trend to crude oil with fluid loss agents, however, increased the incidence of screen-outs until a relationship between injection rates and screenouts was found. Increased injection rates reduced the probability of a screen-out and equipment was built to provide higher rates.

With the further study on foaming agent performance, steam flooding assisted by nitrogen foam has been applied more widely. But the flexibility of this technology in heterogeneous shallow layer heavy oil reservoir has not been fully researched. Through introducing a new dimensionless parameter—foam comprehensive evaluation index (FCEI), we use physical simulation to evaluate foaming agents. Then we make five sand filling tubes modeling permeability contrast in the light of Henan heterogeneous shallow layer heavy oil reservoir. Based on two kinds of foam-injected methods (steam following or not) impact analyses, the applicability of foam to multi-permeability contrast is further discussed. Furthermore, we use numerical simulation to optimize parameters including foam slug size, nitrogen steam ratio, foam injection interval and production-injection ratio, which applied to this type of reservoir. The obtained results show that through foaming coefficient and decay coefficient, FCEI can unify the criteria of foam screening by taking foam volume and half-life into consideration. On even ground, compared with cold foam flooding, the oil production of unit foaming agent of hot foam flooding stays 1.24 % higher. There exists none negative correlation between foam's contributions to each layer's flooding efficiency and permeability. Two methods both indicate that the middle permeability layer, of which the producing degree is similar with lower ones, has great exploitation potential. When injected with cold foam, the start-up pressure of heterogeneous formations increases linearly along with the increase of permeability grade, but for hot foam, this value increases in function of power. And to higher permeability contrast layers, hot foam is better. Finally, under hot foam slug injection condition, the optimum foam slug size is 0.02PV, the optimum nitrogen steam ratio is 20:1, the optimum foam injection interval is 90 days and the best production injection ratio is 1.32:1. Based on the study, this technology has been applied for selected field sites in 2011, and preliminary results have been achieved. The results demonstrate that this research can play an important guiding role in applying steam flooding assisted by nitrogen foam to heterogeneous shallow layer heavy oil reservoir.

Summary For several years, carbon dioxide (CO2) has been added to fracturing fluids at concentrations of 100 to 500 cu ft/bbl (18 to 90 m3/m3) to assist in post-treatment cleanup. In some instances, this has eliminated swabbing after treatment. A recent technique increases the concentration of liquid CO2 to 50% of the total injected volume, approximately 3,000 cu ft/bbl (540 m3/m3). Distinguishing features of this technique are improved fluid-loss control, higher injection rates, increased proppant concentrations, faster fluid recovery, and improved production. Introduction Since the early 1960's, liquefied CO2 has been used widely as an additive to hydraulic fracturing and acid treatments to improve recovery of treating fluid. CO2 may exist as liquid, gas, or solid (Fig. 1). It has a critical temperature of 87.8 degrees F (31 degrees C) and a critical pressure of 1,071 psia (7.4 MPa). During a fracturing treatment, the liquefied CO2 nominally is injected below critical temperature and remains liquid until heated. After CO2 enters the perforations, it may expand into a gaseous state, which provides improved fluid-loss control. The injected liquid CO2 flows back as gas after treatment, along with some fracturing and formation fluids. Mechanism of Fracturing With High CO2 Concentrations When the liquid CO2 is commingled with gelled water, the mixture remains liquid until heated to the critical temperature of 87.8 degrees F, when CO2 begins to vaporize. Even at high temperatures, the solubility of CO2 in water remains high (Fig. 2). 1 This property is a big advantage in recovering the fracturing fluid. It provides a long-sustained solution-gas drive. Fig. 3 shows the high solubility of CO2 in crude oil. The CO2 that goes into solution in a crude oil also imparts a solution-gas drive to the affected fluids when pressure is reduced. Fig. 4 shows that CO2 reduces the viscosity of formation crude oils. Although the amount of CO2 that enters the formation during the fracturing treatment is probably insufficient to reduce oil viscosity deep in the reservoir, the injected CO2 may contact the formation oil near the created fracture. This can reduce oil viscosity in this vicinity and, thereby, improve cleanup after treatment. Fluid retention in a formation is related to interfacial tension of fluids in the reservoir and capillary effects. Fig. 5 shows a significant reduction in interfacial tension when water is saturated with CO2 under pressure. Simon et al. reported interfacial tensions of CO2 with crude oils above saturation of less than 2 dyne/cm (2 mN/m) at 3,000 psi (20.8 MPa). A decrease of 30 to 40% in interfacial tension in laboratory experiments was reported when water was saturated with CO2. Reductions in interfacial tension aid capillary flow of fluids in the minute pores in the formation and help prevent water blocks. The use of high CO2 concentrations reduces the amount of water injected and, consequently, the amount retained in the formation. This significantly decreases water volume injected, water/clay contact time, and cleanup time after treatment. Comparison of CO2 With Other Energized Fracturing Fluids Other energized fluids such as nitrogen, liquefied petroleum gas mixed with CO2, and stable (50 to 80% nitrogen) foams have been used successfully as fracturing fluids. Liquefied petroleum gas has been eliminated as a viable fracturing energy gas because of its flammability. JPT P. 135^

Enhancing oil recovery by injecting stable foam has been an interesting topic in the oil and gas literature lately. The use of nanoparticles, especially silica, is known for its ability to enhance foam stability, and lately, there has been research demonstrating the advantages of carbon nanotubes over silica nanoparticles in that aspect. In this paper, the addition of a partially hydrolyzed polyacrylamide (HPAM) to a multiwalled carbon nanotubes (MWCNT)-enhanced surfactant solution is being experimentally investigated for enhanced oil recovery (EOR) purposes. The proposed HPAM-MWCNT-IOS foam system was evaluated at ambient conditions for foam stability in the presence and in the absence of crude oil. The surfactant, the nanotubes and the polymer concentrations were all optimized for the maximum foam half-life using a bottle test. Furthermore, the effect of adding HPAM on the system's salt tolerance and viscosity was identified. Measurements of surface tension, interfacial tension and contact angle were also done. Finally, coreflood experiments using 6-inches long Berea sandstone cores were carried out to calculate the mobility reduction factor (MRF) at 150°F and 2500 psi overburden pressure. Nitrogen foam was injected as a tertiary recovery system following a waterflooding stage. The pressure-drop across the core was measured throughout the process. Additionally, the volumes of produced oil were measured as a function of injected pore volumes to compare the incremental oil recovery of the different systems. The optimum concentrations of IOS, MWCNT and HPAM were found to be 0.5 wt%, 500 ppm and 500 ppm respectively. The addition of HPAM to MWCNT-stabilized foam increased the foam half-life in the presence of crude oil by 300%. The HPAM-CNT-IOS solution was also found to tolerate higher salt concentrations compared to the MWCNT-IOS solution. The addition of HPAM also increased the viscosity of the nanofluid by several orders of magnitude. All systems experience a shear thinning behavior. Finally, the coreflood tests run at 150°F showed that the mobility reduction was doubled, and after 24 pore volumes of foam injection, the percentage of oil recovery increased from 47% with no polymer (HPAM) to 68% with HPAM. MWCNT-stabilized foam was already proven previously to enhance the performance of standalone-surfactant foam in reservoir conditions. However, in this study, it was shown that HPAM-MWCNT-stabilized foam outperforms MWCNT-stabilized foam. The addition of the polymer to the nanofluid was shown to further enhance foam stability, salt tolerance, mobility reduction factor and oil recovery.

Hydrocarbon gas often contains some amounts of heavier hydrocarbon and non-hydrocarbon components that contribute to its properties (i.e. viscosity and density). Prediction of the density and viscosity values for hydrocarbon gases is necessary in several hydrocarbon gas engineering calculations such as the calculation of gas reserves, gas metering, gas compression, estimating the pressure gradient in gas wells and for the design of pipeline and surface facilities. Literature correlations for the density and viscosity of pure hydrocarbon gas such as methane, ethane, propane, butane and isobutene are available. However, wide-ranging and accurate correlations for predicting the gas viscosity and density are not available for gas mixtures associated with heavier hydrocarbon components and impurities components such as carbon dioxide, nitrogen, helium and hydrogen sulphide. This paper presents two new models for estimating the density and viscosity of pure hydrocarbon gases and hydrocarbon gas mixtures containing high amounts of pentane, plus small concentrations of non-hydrocarbon components (i.e. carbon dioxide, nitrogen and helium), over a wide range of temperatures and pressures on the basis of fuzzy logic approach. The density model was developed using apparent molecular weight, pseudo-reduced temperature and pseudo-reduced pressure. However, the viscosity model was developed using density, apparent molecular weight and pseudo-reduced temperature. The fuzzy models were derived from 5,350 measurements of density and viscosity of various pure gases and gas mixtures. The partitioning of the input space into the fuzzy regions, represented by the individual rules, was obtained through fuzzy clustering. Accuracy of the new fuzzy models was compared to various literature correlations by blind tests using 1,460 measurements of density and viscosity. The results show that the new fuzzy models are more accurate than the compared correlations. Introduction Accurate determination of the density, viscosity and phase behaviour of pure hydrocarbon gases and hydrocarbon gas mixtures is essential for reliable reservoir characterization and simulation and, hence, for optimum usage and exploitation. The variety of possible natural gas mixtures at different conditions of interest preclude obtaining the relevant data by experimental means alone, thus, requiring the development of prediction methods. Natural gas is a mixture of many components. Wide ranging correlations for the viscosity of the lower alkanes, such as methane, ethane, propane, butane and iso-butane, have already been developed and are available in the literature(1–3). However, wide-ranging correlations are often not readily available for many of the higher alkanes and impurities such as carbon dioxide and hydrogen sulfide. These impurities may be present in small quantities in natural gas and are important when modelling the mixture properties(4). In this paper, the fuzzy logic technique was applied for developing new efficient empirical models to estimate density and viscosity of pure hydrocarbon gases (from methane to pentane) and hydrocarbon gas mixtures (different gas mixtures of methane with ethane and/or propane,...., n-Decane) containing small concentrations of non-hydrocarbon components (i.e. carbon dioxide, nitrogen and helium) over a wide range of temperatures (0–238 °C) and pressures (1–890 bar). The new models are designed to be simpler and more efficient than the existing equations of state (EOS).