An Experimental Study at an Abu Dhabi Reservoir of Asphaltene Precipitation Caused By Gas Injection

Abstract

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

Ready for Gas Injection: Asphaltene Risk Evaluation by Mathematical Modeling of Asphaltene-Precipitation Envelope (APE) With Integration of All Laboratory Deliverables

“…The increase of asphaltene risks through gas injection has been recognized as a general rule (Kokal et al 2003;Srivastava et al 1999;Parra-Ramirez et al 2001;Sarma 2003;Jamaluddin et al 2000;Kokal et al 2004;Negahban et al 2005;Okwen 2006; Moghadasi et al 2006). A preparatory evaluation of asphaltene behavior under gas-mixing conditions is important to minimize risks and to optimize the gas-injection project.…”

Investigation of asphaltene precipitation in miscible gas injection processes: experimental study and modeling

“…Hu et al (2004) studied the effects of operating pressure, injected CO 2 concentration, and multiplecontact on the onset and amount of asphaltene precipitation. Negahban et al (2005) discussed experimental work associated with the evaluation of asphaltene precipitation due to the injection of a synthetic gas for a field in the UAE. Idem et al (2002) used a molar CO 2 programmed titration technique to evaluate the kinetics of CO 2 -induced asphaltene precipitation from three Saskatchewan crude oils under isothermal and isobaric reservoir conditions and formulated a kinetic model for the data.…”

“…It is well known that the injection of CO 2 , N 2 and hydrocarbon gases changes the solubility of heavy components in the reservoir oil and causes asphaltene instability (Yang et al, 1999;Srivastava et al, 1999;Jamaluddin et al, 2002;Takahashi et al, 2003;Hu et al, 2004;Negahban et al, 2005;Verdier, 2006;Dehghani et al, 2008). Hirschberg et al (1988) applied polymer solution theory to develop a solubility model for asphaltene precipitation.…”

A Successful Application of Fiber-Optic-Enabled Coiled Tubing With Distributed-Temperature Sensing Along With Pressures To Diagnose Production Decline in an Offshore Oil Well

“…They may start to precipitate once the stability of the colloidal suspension is destabilized, which is caused by the changes in temperature and/or pressure during primary depletion (de Boer et al 1995). On the other hand, asphaltenes have been reported to become unstable as a result of fluid blending (commingling) of fluid streams (Catalan et al 1998) as well as by gas injection during improved oil-recovery (IOR) operations (Koch 1956;Thomas 1998;Burke et al 1990; Leontaritis and Mansoori 1988;Negahban et al 2005). Waxes, on the other hand, are also high-molecular-weight, highly saturated organic substances.…”