Asphaltene precipitation from live crude oils that occurs due to pressure reduction can foul and clog oil production equipment, at the well surface, in the borehole, and even in the subsurface formation, thus is of considerable interest to oil operating companies. We employ near-infrared (NIR) spectroscopy to characterize this asphaltene precipitation process; in particular, the independent measurements on asphaltene flocculation of wavelength dependence of optical scattering and of sedimentation rates are performed. Here, it is established that different asphaltene flocs form during depressurization of crude oil. Furthermore, the initial precipitate is probably not problematic in the production of crude oil, relaxing constraints imposed by asphaltene considerations. Additionally, the asphaltene precipitation process is shown to be largely reversible in the minutes time frame, but subtle irreversibilities are suggested. Compressibility is measured using NIR techniques to validate our methods. Optical spectroscopy on optically thin samples is found to be a powerful and indispensable tool to characterize asphaltene precipitation.

In this paper we investigate experimentally the effect of surfactants on the formation kinetics of methane hydrate. The compounds tested include: anionic, cationic and nonionic surfactants. Experimental results indicate that surfactants (at concentrations levels near their CMC) do not influence the thermodynamics, however, they have a strong influence on the kinetics of gas dissolution in the water phase as well as on the overall rate of hydrate formation. In addition, the formed hydrate particles in the presence of the various surfactants exhibit diverse agglomeration characteristics. This work is part of an overall effort to develop the technology required for the safe operation of offshore oil and gas transportation pipelines without inhibitors.

Asphaltenes are the n-pentane or n-heptane insoluble fractions of crude oil that remain in solution under reservoir temperature and pressure conditions. They are destabilized and start to precipitate when the pressure, temperature, and/or composition changes occur during primary production. The precipitated asphaltene particles will then grow in size, and may start to deposit onto the production string and/or flowlines, causing operational problems. In this paper, our emphasis is to identify the first pressure and/or temperature conditions at which the asphaltene will start to precipitate for two reservoir oils. Four different laboratory techniques were independently used to define the onset of the asphaltene precipitation envelope. These methods are:gravimetric;acoustic resonance;light scattering; andfiltration. The gravimetric method was found to be precise, and within the accuracy of the analytical methods. However, the method was time consuming. The acoustic resonance technique (ART) was fast and less subjective, but it did not define the lower asphaltene boundary. The interpretation of the onset pressure from the near-infrared (NIR) light-scattering technique (LST) was subjective to a degree. However, the NIR response defined the upper and lower boundaries of the asphaltene envelope and the bubblepoint pressure, as did the gravimetric technique. In a manner similar to those of the gravimetric technique and LST, the filtration technique can also define the upper and lower asphaltene phase boundaries, in addition to the bubblepoint pressure. The filtration technique is fast compared to the gravimetric technique, but takes more time than the ART and LST methods. Introduction Asphaltenes remain in solution under reservoir temperature and pressure conditions. They start to precipitate when the stability of the colloidal dispersion is disturbed. This disturbance can be caused by changes in pressure, temperature, and/or composition of the oil. Precipitation and deposition of asphaltenes have reportedly caused operational problems, ranging from plugging of tubulars and flowlines(1–3) to clogging of production separators(4). Leontaritis and Mansoori present a comprehensive description of field problems caused by asphaltene deposition(5). Figure 1 schematically presents the asphaltene-related problems that may occur in the field. Asphaltene precipitation problems can be categorized as follows:Precipitation can be caused by the changes in temperature and/or pressure during primary depletion.Precipitation can be caused by blending or commingling of two noncompatible reservoir fluid streams (i.e., subsea completions), acid stimulation and/or enhanced recovery injection gases (CO2, H2S, or rich gas). The correct operating procedure to minimize the asphaltene problem is not well understood. We believe a better understanding of the fundamental processes leading to solids precipitation is a prerequisite to management and prevention of production problems. Primarily, two theoretical approaches have been presented in the literature to compute phase separations of asphaltene during primary production. These approaches include association modeling(6, 7) and calculation of asphaltene solubility parameters with the Flory Huggins polymer phase separation technique.(8, 9) Asphaltene destabilization caused by solvent injection and consequent alteration of the rock surface wettability have also been reported in the literature, but are not discussed here.(10).

Summary This paper discusses experimental work associated with the evaluation of asphaltene precipitation for a field in Abu Dhabi, UAE. This reservoir is in the early stages of development and will be put on production using a combination of gas-, water-, and water-alternating-gas- (WAG) injection schemes in early 2006. The field has not shown operational problems resulting from asphaltene precipitation during primary production. Laboratory experiments using the transmittance of an optimized laser light in the near-infrared (NIR) wavelength (˜1600 nm) were used to first confirm the stability of asphaltene in the reservoir fluid. Two cases covering the expected extremes in terms of the field gas/oil ratio (GOR) were evaluated. Isothermal depressurization tests were also conducted at reservoir, wellhead, and separator temperatures (250, 190, and 130oC, respectively). Several additional light-transmittance experiments were conducted to evaluate the asphaltene-instability regions resulting from reservoir-fluid contact with various concentrations of rich gas and carbon dioxide (CO2). Measurements using high-pressure filtration were also collected to quantify the bulk precipitation of asphaltene with various molar concentrations of gas. Finally, tests were conducted using state-of-the-art technologies to evaluate the consistency of the initial NIR runs. These technologies involved the use of a spectral-analysis system (SAS) to evaluate asphaltene-particle size and growth rate and high-pressure microscopy (HPM) images to visually confirm the measurements. Results indicated that rich hydrocarbon gas in contact with reservoir fluid destabilizes asphaltene. The amount of the bulk precipitation increased with higher concentrations of rich gas in the reservoir fluid. Particle sizes were estimated to be in the range of 0.5 to 1 µm. The effect of CO2 was found to be less severe with regard to asphaltene instability. Introduction Because the reservoir is still in early development, and will not be put on production until early 2006, a feasibility study was undertaken to evaluate the potential of improved oil recovery (IOR)—by using a combination of gas-, water-, and WAG-injection schemes—as well as asphaltene compatibility with various injection gases. To cover the range of reservoir fluids encountered in the field, two extreme cases of GOR were evaluated. A summary of the reservoir-fluid properties for each of these fluids is provided in Table 1. These properties confirm a typical black-oil reservoir fluid. Properties to note for the stock-tank oil (STO) include an n-C7-insoluble asphaltene content of approximately 1.0 wt% in Fluid A and approximately 0.5 wt% in Fluid B. Wax contents (Universal Oil Products 46 Summary Foam stability is an important parameter for foam fracturing. Bench-top testing is useful for screening but does not address the necessary conditions of temperature, pressure, pH [particularly with carbon dioxide (CO2) systems], and dynamic-flow conditions that can have unexpected influence on the foam's performance. A laboratory apparatus has been constructed for measuring the rheology of circulating-foam fluids to 400°F and 3,000 psi. The apparatus is equipped with a circulation pump, view cells, foam generator, mass flowmeter, and piping for loading a foam of the desired quality using either nitrogen (N2) or CO2. The foam rheometer is intended for evaluation of foam stability with time and comparison of various foam formulations for application in foam fracturing. The foam loop was designed to mimic shear rates found in a fracture or reservoir, which are typically 200 s-1 or less. The rheology is measured by monitoring the pressure drop across a 20-ft length of ¼-in. tubing maintained at temperature in an oven. Flow rate is continuously adjusted, to ensure a constant shear rate in the tubing, by the software using continuous mass-flowmeter input. Results relating to CO2 and N2 foams are discussed with emphasis on foam persistence, bubble size and population, and the rheological behavior with time. Temperature, pressure, and additives affect both foam texture and foam stability. The adoption of a standard technique patterned after this work for evaluating foam rheology could impact the use and development of foam fluids in the future. Introduction Foam-fracturing fluids are used in approximately 40% of all fracturing-stimulation treatments executed in North America. Foam-fluid functional properties, such as proppant-carrying capacity, resistance to leakoff, and viscosity for fracture-width creation, are derived from the foam structure and the external phase properties. Moreover, the foam must have structural stability to maintain its performance throughout the treatment. A major objective of this work was to develop an efficient method of evaluating the time-dependent properties of foam-fracturing fluids under meaningful conditions. The reasons for this objective are to evaluate the effectiveness of surfactants and to determine the two engineering parameters, behavior index (n') and consistency index (K'), used by fracturing simulators to estimate treatment operating parameters and fracture geometry. 64) of 1.9 wt% and 2.9 wt% were measured in Fluids A and B, respectively. The respective STO cloud points were 102 and 99oF. The wax content did not appear to raise any concern because there was no evidence of an operational problem in the field related to wax. Also, the subject reservoir is not expected to cause operational problems resulting from asphaltene precipitation during primary production. Asphaltenes are high-molecular-weight organic fractions of crude oils that are soluble in toluene, but insoluble in alkanes (e.g., n-heptane and n-pentanes). Asphaltenes tend to remain in solution or in colloidal suspension under reservoir temperature and pressure conditions. They may start to precipitate once the colloidal suspension is destabilized, which is caused by changes in temperature and/or pressure during primary depletion.1 Asphaltenes have also been reported to become unstable as a result of blending (commingling) fluid streams,2 as well as by gas injection during IOR operations.3–7