A region of broad nonlinear curvature is observed in DSC traces of ABA copolymers during temperature sweeps between the glass transition temperatures of the two principal microphases. This curvature is attributed to a smoothly varying composition profile through the interfacial region lying between microphases. The shape of the DSC curve is proposed to be a fingerprint for a given profile. This curvature is, however, shown to be a possible source of uncertainty in precise evaluation of Tg for the microphases and the reported enhanced breadth of these transitions. In addition, microphase separation temperatures are readily identifiable from DSC traces, and their values correspond well to the predictions of Leary‐Williams theory. © 1999 John Wiley & Sons, Inc. J Polym Sci B: Polym Phys 37: 267–274, 1999

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWater is invariably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path, stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils where steam is used to reduce the viscosity of heavy oil or in cases where submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy oil production systems, knowledge of the realistic viscosities of the emulsified heavy oil under the actual production conditions is necessary. This study is an attempt to investigate the effect of water content, pressure and temperature i.e. operating conditions on the viscosity of live heavy oil emulsions.Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil-water emulsions were prepared in a concentric cylinder shear cell using synthetic formation water, under predetermined pressure, temperature, and shear conditions. The stability of live emulsions was investigated using a fully visual PVT cell, while viscosities were measured using a pre-calibrated high-pressure capillary viscometer. Viscosities were measured at least in three different flow rates at the testing conditions. In addition to live oil emulsion studies, the stability and droplet size distribution of STO emulsions were also determined.Experimental results indicated that the inversion point for the stock tank oil emulsions was approximately 60 % water cut (volume) and that the average droplet size was increasing with water content. For all measured cases, viscosities varied with temperature according to an Arrhenius relation while viscosities did not indicate any variation with flow rate (shear) within the range of tested flow rates. Measured viscosities also increased as pressure decreased below the bubble point of the sample as lighter hydrocarbon components evolved. The measured viscosities increased as much as 500% due to the presence of emulsions before sharp drop in viscosity beyond the inversion point. The variation of viscosity with water content for live emulsion samples indicated that the inversion point for live emulsions is similar to that of stock tank oil samples.

Summary Water is invariably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path, stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils, where steam is used to reduce the viscosity of heavy oil, or in cases in which submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy-oil production systems, knowledge of the realistic viscosities of the emulsified heavy oil, under the actual production conditions, is necessary. This study is an attempt to investigate the effect of water content, pressure, and temperature (i.e., operating conditions on the viscosity of live heavy-oil emulsions). Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil/water emulsions were prepared in a concentric cylinder shear cell using synthetic formation water, under predetermined pressure, temperature, and shear conditions. The stability of live emulsions was investigated using a fully visual pressure/volume/temperature (PVT) cell, while viscosities were measured using a precalibrated, high-pressure capillary viscometer. Viscosities were measured at least in three different flow rates at the testing conditions. In addition to live-oil emulsion studies, the stability and droplet size distribution of STO emulsions were also determined. Experimental results indicated that the inversion point for the STO emulsions was approximately 60% water cut (volume), and the average droplet size was increasing with water content. For all measured cases, viscosities varied with temperature according to an Arrhenius relation, while viscosities did not indicate any variation with flow rate (shear) within the range of tested flow rates. Measured viscosities also increased as pressure decreased below the bubblepoint of the sample as lighter hydrocarbon components evolved. The measured viscosities increased as much as 500% because of the presence of emulsions before a sharp drop in viscosity beyond the inversion point. The variation of viscosity with water content for live emulsion samples indicated that the inversion point for live emulsions is similar to that of STO samples. The experimental results are also used to analyze and evaluate the performance of an ESP system when water cut increases and causes emulsion in a well. Introduction As an oilfield ages, the rate of water production increases. With enough shear force (e.g., flow through a downhole pump or a flow restriction such as a choke valve or orifice), a stable emulsion can be formed. Presence of inorganic solids such as sand, clay, and corrosion products, together with surface-active materials such as asphaltenes and naphthenic acids, also enhance the stability of emulsions (Kokal 2005). Because of the presence of these elements, the occurrence of tight emulsions in the production facilities is quite common. In some cases, emulsions may also form in the near-wellbore region, leading to emulsion blockage of porous media (Kokal et al. 2002). In addition to formation blockage and general difficulty in the separation of oil and water in production facilities, one of the main drawbacks of emulsion formation is an increase in the apparent viscosity of the oil. Viscosity of water-in-oil emulsions increases as the water cut increases before the so-called emulsion inversion point, beyond which the continuous phase changes to water (i.e., water-in-oil emulsion switches to oil-in-water emulsion). It has been shown that the viscosity of the water-in-oil emulsion may increase as much as one order of magnitude or even higher over the viscosity of the dry oil (Singh et al. 2004). In oil-in-water emulsions, viscosity decreases with an increase in water content. Therefore, the maximum apparent viscosity of emulsions occurs at the emulsion inversion point (Szelag and Pauzder 2003).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWater is invariably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path, stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils where steam is used to reduce the viscosity of heavy oil or in cases where submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy oil production systems, knowledge of the realistic viscosities of the emulsified heavy oil under the actual production conditions is necessary. This study is an attempt to investigate the effect of water content, pressure and temperature i.e. operating conditions on the viscosity of live heavy oil emulsions.Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil-water emulsions were prepared in a concentric cylinder shear cell using synthetic formation water, under predetermined pressure, temperature, and shear conditions. The stability of live emulsions was investigated using a fully visual PVT cell, while viscosities were measured using a pre-calibrated high-pressure capillary viscometer. Viscosities were measured at least in three different flow rates at the testing conditions. In addition to live oil emulsion studies, the stability and droplet size distribution of STO emulsions were also determined.Experimental results indicated that the inversion point for the stock tank oil emulsions was approximately 60 % water cut (volume) and that the average droplet size was increasing with water content. For all measured cases, viscosities varied with temperature according to an Arrhenius relation while viscosities did not indicate any variation with flow rate (shear) within the range of tested flow rates. Measured viscosities also increased as pressure decreased below the bubble point of the sample as lighter hydrocarbon components evolved. The measured viscosities increased as much as 500% due to the presence of emulsions before sharp drop in viscosity beyond the inversion point. The variation of viscosity with water content for live emulsion samples indicated that the inversion point for live emulsions is similar to that of stock tank oil samples.

The near-infrared (NIR) light scattering technique, commercially known assolids detection system (SDS) is widely used to determine the asphalteneprecipitation pressure in reservoir fluids. In this study the SDS is used tocompare samples collected from the same zone in the same well at the same timebut in different sample chambers. The SDS technique is further compared withhigh pressure filtration for the same fluid studied by SDS In addition, asphaltene precipitation as a function of pressure was determined. The results of this study indicate that the SDS test provides a quick toolto determine the asphatene precipitation pressure but has limited sensitivity.Furthermore, the bulk of asphaltenes tended to precipitate within a narrowpressure range near the precipitation onset pressure for the fluid sampletested in this study. Introduction Asphaltene precipitation and deposition from reservoir fluids due topressure depletion can be a serious flow assurance problem. This hassignificant impact on the development of deep-water reservoirs due to enormouscost associated with inhibition and remediation of asphaltenes. Remediationcost increases with water depth for offshore fields (MMS/DeepStar Workshop onProduced Fluids, Offshore Technology Conference, Houston, TX; May 4, 1995):Deepwater projects may spend $5–10MM for asphalteneremediation/control.Each well intervention incident may cost $0.5–1MM neglecting lostproduction, and each flow line mechanical remediation may cost about$25MM. Therefore, the understanding of asphaltene precipitation and depositionpotential from reservoir fluids is an important consideration in the designphase of the development of remote / deep-water reservoirs. Deposition of asphaltenes can occur in the tubing, flow lines and surfacefacilities leading to operational problems and loss in production. For the Gulfof Mexico (GoM) fluids the asphaltene instability increases with decreasingtemperature. Thus, the asphaltene deposition (precipitation) in the long subseatiebacks, tubing and surface facilities will increase with a reduction in fluidtemperature. Though there is considerable discussion of the reversibility ofashphaltene precipitation, the asphaltenes precipitated from GoM reservoirfluids are proven to be reversible (at least partially). A detailed review ofthe literature on asphaltene related production problems has been published byKokal et al.