Casing temperatures and wellbore heat losses are critical variables in steam and hot water injection wells. Several papers have been written presenting methods of estimating these parameters if the over-all heat transfer coefficient is known. The over-all heat transfer coefficient for a wellbore is developed from its component terms to promote a better understanding of the concept. Specific methods have been selected from the heat transfer literature for estimating the size of each heat transfer component. Simplified calculation procedures are suggested for determining the over-all heat transfer coefficient. Comparison of calculated and measured casing temperatures during steam injection confirms the basic formulation and applicability of the suggested procedure for engineering calculations. Introduction The design of steam and hot water injection projects requires estimation of casing temperatures and wellbore heat loses. Several authors have shown that wellbore heat losses and casing temperatures can be calculated if the over-all heat transfer coefficient is known. This article discusses methods of determining the over-all heat transfer coefficient from the process variables. Development The steady-state rate of heat flow through a wellbore Q Btu/hour is proportional to the temperature difference between the fluid and the formation, and the cross-sectional area perpendicular to the direction of heat flow. The proportionally factor, called the over-all heat transfer coefficient, represents the net resistance of the flowing fluid, tubing, casing annulus, casing wall and cement sheath to the flow of heat. Thus, we can write Q = Uj Aj Tj............................ (1) Eq. 1 defines Uj, the over-all heat transfer coefficient based on the characteristic area A, and a characteristic temperature difference T,. Subscript j in Eq. 1 identifies the surface upon which these quantities are based. In theory, any radial surface could be used to determine the characteristic area. Some choices are more convenient to work with than others. For example, if hot fluid is injected down tubing it is preferred to let A, be the outside surface area of an incremental length of injection tubing, 2 to L, and let T, be the difference between the temperature of the flowing fluid Tj and the temperature at the cement-formation interface (the drill hole) Th. Then Uj = Uo, referring to the outside tubing surface area, and Eq. 1 would be Q = 2 to Uto (Tj- Th) L................ (2) If the fluid is injected down the casing or casing annulus. the characteristic area could be the inside surface area of the casing, and Eq. 1 would be written as Q = 2 ci Uci (Tj - Th) L..................(3) Subscript ci refers to the inside casing surface. An expression for the over-all heat transfer coefficient for any well completion can be found by considering the heat transfer mechanisms between the flowing fluid and the cement-formation inter-face. A brief derivation of the over-all heat transfer coefficient is presented in the following paragraphs for the case of a hot fluid flowing through tubing insulated with a dry air annulus. Other cases can be derived easily once the basic concepts are understood. Fig. 1 shows the wellbore model which will be used to derive Uto. Heat Transfer Mechanisms The rate of heat transfer between the flowing fluid and inside tubing wall is given by Eq. 4. Q = 2 ti hj (Tj - Tti) L...................(4) hf, is defined by Eq. 4 and is the film coefficient for heat transfer based on the inside surface area of the tubing (subscript ti) and the temperature difference between the flowing fluid and the inside tubing wall Tj-Tti. Heat flow through the tubing wall, casing wall and the cement sheath occurs by conduction. Fourier discovered that the rate of heat flow through a body is directly proportional to the temperature gradient in the medium. JPT P. 607ˆ

Building on the comprehensive, fundamental mechanisms and mathematical computations detailed in the First Edition, the new Second Edition of Enhanced Oil Recovery presents the latest insights into the applications of EOR processes, including-Field-scale thermal-recovery such as steam-assisted gravity drainage and cyclic steam stimulation-Field-scale polymer flooding including horizontal wells-Field-scale miscible-displacement processes such as CO2 miscible flooding-Laboratory-scale chemical flooding in the development and testing of surfactant formulations An invaluable tool for petroleum engineering students, Enhanced Oil Recovery also serves as an important resource for those practicing oil recovery in the field or engaged in the design and operation of commercial projects involving enhanced-or improved-oil-recovery processes. A prior understanding of basic petrophysics, fluid properties, and material balance is recommended.

Heterogeneity of oil reservoirs often leads to unproductive cycling of injected oil recovery chemicals, resulting in the loss of significant quantities of reserves. To maximize recovery efficiency, a blocking agent may be placed deep into high-permeability channels so that the subsequently injected chemicals can be redirected into previously unswept regions. Cr(III)−polyacrylamide gels have been used extensively in field applications as blocking agents for sweep improvement; however, the gelation time of the current state-of-the-art is too short to achieve in-depth placement. This paper describes a novel approach of using polyelectrolyte complex nanoparticles to entrap and control the release Cr(III) to effectively extend gelation time. Self-assembly of polyethylenimine (PEI) and dextran sulfate (DS) resulted in the formation of ∼100−200 nm particles that efficiently entrapped chromium while maintaining colloidal stability in water or gelant. Although the addition of chromium chloride to HPAM typically produced gels in minutes, chromium was efficiently sequestered in nanosuspensions of polyelectrolyte complexes, resulting in a significant delay in gel formation that was dependent on pH, ionic strength, and temperature. The gel formation kinetics of PEI, polyelectrolyte complexes (PECs) of PEI and DS, and PECs loaded with chromium were compared. PEI, a known cross-linker of HPAM, produced a steady increase in gelant viscosity over time. PECs without chromium demonstrated a delayed gel formation compared to PEI but possessed a similar creeping increase in viscosity. In contrast, PECs loaded with chromium typically showed minimal viscosity increase over time followed by an abrupt viscosity increase, resulting in gel formation. This study suggests that PECs offer a flexible nanotechnology platform that may enable novel chemical delivery schemes in the oil and gas industry.

Retention and flow characteristics of a solution containing Pusher 700~a high-molecular-weight, partially hydrolyzed polyacrylamide, were studied in an 86-md core made by compacting Teflon powder. The quantity of polymer retained during linear displacement experiments ranged from 10 to 21 /lgmlgm for polymer concentrations of 100 to 500 ppm in 2-percent NaC! solutions. Nearly all retention was attributed to mechanical entrapment because of low polymer adsorption on the Teflon surface. Flow rate affected polymer retention. An increase in velocity was accompanied by polymer retention. Polymer was expelled when the flow rate was reduced. Inaccessible pore volume was about 19 percent of the total pore volume.Resistance factors in different sections of the core ranged from 2 to 10 for solutions of 100 to 500 ppm polymer concentration in 2-percent NaC!. Permeability reduction resulting from polymer retention produces the resistance factor in most of the core at a velocity of 3.2 ftlD. Resistance factors in the Teflon cor~s were two to three times lower than those reported for natural porous media where polymer is also retained by adsorption.

Swelling/extraction tests are single-contact phase-behavior experiments to measure the solubility of CO 2 dissolved in crude oil and the amount of hydrocarbon that CO 2 can extract or vaporize from crude oil. The tests are commonly conducted in a visual PVT cell with a large sample size (40-100cc). In this paper, an easy operated apparatus capable of determining phase behavior with a significantly smaller sample size (3 to 14 cc) is described. The apparatus consists of a high-pressure view cell, high-pressure and precision syringe pump filled with CO 2 , a water bath, and accessories to measure the temperature and pressure. The device is capable of determining vapor-liquid, liquid-liquid and vapor-liquid-liquid equilibrium commonly observed in a high pressure CO 2 enhanced oil recovery process. The solubility of CO 2 in oil, the expansion volume of oil due to the dissolution of CO 2 as well as the phase transition during the test were quantified with excellent reproducibility. The molar volume of oil saturated with CO 2 correlated linearly with the mole fraction of dissolved CO 2 suggesting ideal mixing in the liquid phase. The phase behavior between CO 2 and crude oil samples with different composition, temperature and pressure is discussed.