J. Energy Resour. Technol. 1998;120(1):1. doi:10.1115/1.2795003.
Commentary by Dr. Valentin Fuster


J. Energy Resour. Technol. 1998;120(1):2-7. doi:10.1115/1.2795006.

Improved and novel prediction methods are described for single-phase and two-phase flow of non-Newtonian fluids in pipes. Good predictions are achieved for pressure drop, liquid holdup fraction, and two-phase flow regime. The methods are applicable to any visco-inelastic non-Newtonian fluid and include the effect of surface roughness. The methods utilize a reference fluid for which validated models exist. For single-phase flow, the use of Newtonian and power-law reference fluids are illustrated. For two-phase flow, a Newtonian reference fluid is used. Focus is given to shear-thinning fluids. The approach is theoretically based and is expected to be more accurate for large, high-pressure pipelines than present correlation methods, which are all primarily based on low-pressure, small-diameter pipe experimental data.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):8-14. doi:10.1115/1.2795016.

Two-phase flow of oil and water is commonly observed in wellbores, and its behavior under a wide range of flow conditions and inclination angles constitutes a relevant unresolved issue for the petroleum industry. Among the most significant applications of oil-water flow in wellbores are production optimization, production string selection, production logging interpretation, down-hole metering, and artificial lift design and modeling. In this study, oil-water flow in vertical and inclined pipes has been investigated theoretically and experimentally. The data are acquired in a transparent test section (0.0508 m i.d., 15.3 m long) using a mineral oil and water (ρo /ρw = 0.85, μo /μw = 20.0 & σo−w = 33.5 dyne/cm at 32.22°C). The tests covered inclination angles of 90, 75, 60, and 45 deg from horizontal. The holdup and pressure drop behaviors are strongly affected by oil-water flow patterns and inclination angle. Oil-water flows have been grouped into two major categories based on the status of the continuous phase, including water-dominated and oil-dominated flow patterns. Water-dominated flow patterns generally showed significant slippage, but relatively low frictional pressure gradients. In contrast, oil-dominated flow patterns showed negligible slippage, but significantly large frictional pressure gradients. A new mechanistic model is proposed to predict the water holdup in vertical wellbores based on a drift-flux approach. The drift flux model was found to be adequate to calculate the holdup for high slippage flow patterns. New closure relationships for the two-phase friction factor for oil-dominated and water-dominated flow patterns are also proposed.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):15-19. doi:10.1115/1.2795002.

The effect of drag-reducing agents (DRA) on pressure gradient and flow regime has been studied in horizontal and 2-deg upward inclined pipes. Experiments were conducted for different flow regimes in a 10-cm i.d., 18-m long plexiglass system. The effectiveness of DRA was examined for concentrations ranging from 0 to 75 ppm. Studies were done for superficial liquid velocities between 0.03 and 1.5 m/s and superficial gas velocities between 1 and 14 m/s. The results indicate that DRA was effective in reducing the pressure gradients in single and multiphase flow. The DRA was more effective for lower superficial liquid and gas velocities for both single and multiphase flow. Pressure gradient reductions of up to 42 percent for full pipe flow, 81 percent for stratified flow, and 35 percent for annular flow were achieved in horizontal pipes. In 2 deg upward inclination, the pressure gradient reduction for slug flow, with a concentration of 50 ppm DRA, was found to be 28 and 38 percent at superficial gas velocities of 2 and 6 m/s, respectively. Flow regimes maps with DRA were constructed in horizontal pipes. Transition to slug flow with addition of DRA was observed to occur at higher superficial liquid velocities.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):20-26. doi:10.1115/1.2795004.

Accurate modeling of hydrate transportation in natural gas pipelines is becoming increasingly important in the design and operation of offshore production facilities. The dynamics involved in the formation of hydrate particles and in its transportation are governed by the multiphase hydrodynamics equations ensuing from the balance of mass, momentum, and energy. In this study, a two-fluid model is solved to characterize particulate transportation. The numerical algorithm employed is stable and robust and it is based on higher-order schemes. This is necessary since the governing equations describing the simultaneous flow of gas and solid particles are hyperbolic and, thus, admit discontinuities. Specialized higher-order schemes provide a viable approach for efficient frontal tracking of continuity waves in particular. Several simulation experiments that can facilitate thorough understanding of the design and maintenance of pipelines susceptible to hydrate formation are presented.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):27-31. doi:10.1115/1.2795005.

As longer, full well-stream flowlines are utilized to reduce the costs of deepwater and satellite developments, routine production monitoring attains a new level of importance. Of particular interest is the operational impact that blocking agents such as paraffins, asphaltenes, hydrates, and scale can have on the flowlines. Because blockages can reduce and even disrupt production, monitoring flowline performance becomes an economic necessity. This paper considers the application of the backpressure technique as a means of monitoring the growth of blockages in gas flowlines. Using only routine production data, this method quantifies partial blockages by comparing production data to a baseline performance curve. Experimental verification was performed using the LSU 9460-ft flowloop of 4 1/2-in. drillpipe. Multirate tests were conducted using methane at 250–620 psig with partial blockages placed in the flowloop. Good agreement with the backpressure model was observed.

Topics: Methane , Satellites
Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):32-40. doi:10.1115/1.2795007.

Liquid condensation in natural gas transmission pipelines commonly occurs due to the thermodynamic and hydrodynamic imperatives. Condensation subjects the gas pipeline to two-phase transport. Neither the point along the pipeline at which the condensate is formed nor the quantity formed is known a priori. Hence, compositional multiphase hydrodynamic modeling, which couples the multiphase hydrodynamic model with the natural gas phase behavior model, is necessary to predict fluid dynamic behavior in gas/condensate pipelines. A transient compositional multiphase hydrodynamic model for transient gas-condensate two-phase flow in pipelines is presented. This model consists of our newly developed well-posed modified Soo’s partial pressure model in conservative form which serves as the transient multiphase hydrodynamic model, and the phase behavior model for natural gas mixtures.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):41-48. doi:10.1115/1.2795008.

The presence of free gas at the pump intake adversely affects the performance of an electrical submersible pump (ESP) system, often resulting in low efficiency and causing operational problems. One method of reducing the amount of free gas that the pump has to process is to install a rotary gas separator. The gas-liquid flow associated with the down hole installation of a rotary separator has been investigated to address its overall phase segregation performance. A mathematical model was developed to investigate factors contributing to gas-liquid separation and to determine the efficiency of the separator. The drift-flux approach was used to formulate this complex two-phase flow problem. The turbulent diffusivity was modeled by a two-layer mixing-length model and the relative velocity between phases was formulated based on published correlations for flows with similar characteristics. The well-known numerical procedure of Patankar-Spalding for single-phase flow computations was extended to this two-phase flow situation. Special discretization techniques were developed to obtain consistent results. Special under relaxation procedures were also developed to keep the gas void fraction in the interval [0, 1]. Predicted mixture velocity vectors and gas void fraction distribution for the two-phase flow inside the centrifuge are presented. The model’s predictions are compared to data gathered on a field scale experimental facility to support its invaluable capabilities as a design tool for ESP installations.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):49-55. doi:10.1115/1.2795009.

The performance of gas-liquid cylindrical cyclone (GLCC) separators can be improved by reducing or eliminating liquid carryover into the gas stream or gas carryunder through the liquid stream, utilizing a suitable liquid level control. In this study, a new passive control system has been developed for the GLCC, in which the control is achieved by utilizing only the liquid flow energy. A passive control system is highly desirable for remote, unmanned locations operated with no external power source. Salient features of this design are presented here. Detailed experimental and modeling studies have been conducted to evaluate the improvement in the GLCC operational envelope for liquid carryover with the passive control system. The results demonstrate that a passive control system is feasible for operation in normal slug flow conditions. The advantage of a dual inlet configuration of the GLCC is quantified for comparative evaluation of the passive control system. The results of this study could form the basis for future development of active control systems using a classical control approach.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):56-60. doi:10.1115/1.2795010.

At present, no standard of presenting multiphase flow meter (MPFM) uncertainties has been accepted by industry. Consequently, vendors’ specifications may only indicate velocity and component fraction uncertainties, while customers will typically need to know the overall uncertainty of the hydrocarbon (gas or oil) flow rate. Moreover, comparisons between different meters, meter locations, and metering strategies are difficult without the combined uncertainties of the hydrocarbon measurement. A simple uncertainty analysis (UA) is presented as a means of combining individual measurement uncertainties to determine an overall uncertainty for one of the mixture components, e.g., oil rate. The results are displayed as contour lines of constant oil rate uncertainty on plots of gas fraction versus water cut. Examples illustrate how the uncertainty of oil rate measurement might be reduced by operating the meter at higher pressure, or employing partial separation strategies, and limitations of such strategies.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):61-66. doi:10.1115/1.2795011.

Accurate predictions of annular frictional pressure losses (AFPL) are important for optimal hydraulic program design of both vertical and horizontal wells. In this study, the effects of drillpipe rotation on AFPL for laminar, helical flow of power law fluids are investigated through theoretical, study, flow models were developed for concentric and eccentric pipe configurations assuming that pipe rotates about its axis. A hybrid-analytical solution is developed for calculating AFPL in eccentric pipe configuration. Computer simulations indicate that the shear-thinning effect induced by pipe rotation results in reduction of AFPL in both concentric and eccentric pipe configurations. The pressure reduction is most significant for concentric pipe configurations. For conventional rotary drilling geometry and pipe rotary speeds, the reduction in AFPL is small. A number of laboratory experiments conducted on the full-scale TUDRP flow loop are generally in good agreement with the results of modeling. Available fileld data, however, consistently show an increase in AFPL. This behavior is explained by pipe lateral movement (swirling), which causes turbulence and eventually an increase in AFPL.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):67-71. doi:10.1115/1.2795012.

Previous work has demonstrated the mechanism of enhanced corrosion in slug flow due to entrained pulses of gas bubbles (Gopal et al., 1997). Corrosion rate measurements have been made at pressures up to 0.79 MPa and temperatures up to 90°C, and it has been shown that the effect of these pulses of bubbles increases with pressure and Froude number. This paper describes mass transfer measurements under multiphase slug and annular flows using the limiting current density technique. The experiments are carried out in a 10-cm-dia pipe using a 0.01-M potassium ferro/ferricyanide solution in 1.3 N sodium hydroxide for the liquid phase and nitrogen in the gas phase. Froude numbers of 4, 6, and 9 in slug flow have been studied, while gas velocities up to 10 m/s are investigated in annular flows. The results show instantaneous peaks in the mass transfer rates corresponding to the pulses of bubbles in slug flow. Instantaneous increases of 10–100 times the average values in multiphase flow are seen. Peaks are also seen in instantaneous mass transfer rates in some annular flows.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):72-77. doi:10.1115/1.2795013.

The effect of fluid flow on corrosion of steel in oil and gas environments involves a complex interaction of physical and chemical parameters. The basic requirement for any corrosion to occur is the existence of liquid water contacting the pipe wall, which is primarily controlled by the flow regime. The effect of flow on corrosion, or flow-accelerated corrosion, is defined by the mass transfer and wall shear stress parameters existing in the water phase that contacts the pipe wall. While existing fluid flow equations for mass transfer and wall shear stress relate to equilibrium conditions, disturbed flow introduces nonequilibrium, steady-state conditions not addressed by these equations, and corrosion testing in equilibrium conditions cannot be effectively related to corrosion in disturbed flow. The problem in relating flow effects to corrosion is that steel corrosion failures in oil and gas environments are normally associated with disturbed flow conditions as a result of weld beads, pre-existing pits, bends, flanges, valves, tubing connections, etc. Steady-state mass transfer and wall shear stress relationships to steel corrosion and corrosion testing are required for their application to corrosion of steel under disturbed flow conditions. A procedure is described to relate the results of a corrosion test directly to corrosion in an operation system where disturbed flow conditions are expected, or must be considered.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):78-83. doi:10.1115/1.2795014.

CO2 corrosion in carbon steel piping systems can be severe depending on a number of factors including CO2 content, water chemistry, temperature, and percent water cut. For many oil and gas production conditions, corrosion products can form a protective scale on interior surfaces of the piping. In these situations, metal loss rates can reduce to below design allowances. But, if sand is entrained in the flow, sand particles impinging on pipe surfaces can remove the scale or prevent it from forming at localized areas of particle impingement. This process is referred to as “erosion-corrosion” and can lead to high metal loss rates. In some cases, penetration rates can be extremely high due to pitting. This paper combines laboratory test data on erosion-corrosion with an erosion prediction computational model to compute flow velocity limits (“threshold velocities”) for avoiding erosion-corrosion in carbon steel piping. Also discussed is how threshold velocities can be shifted upward by using a corrosion inhibitor.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):84-89. doi:10.1115/1.2795015.

Drill string safety valves (DSSVs) are used to prevent blowouts up the drillpipe when unexpected subsurface pressures are encountered in oil and gas drilling. Several case history reviews of well control events have recently shown evidence of poor reliability with DSSVs. Of the problems reported, valve lock-up was most significant, resulting in failure to open or close due to high actuation torque. This paper describes an experimental apparatus and experimental procedures used to quantify the actuating torque of DSSVs under a variety of common operating conditions. Experimentally obtained torque curves are presented for both commercially available and prototype DSSVs, and the results are discussed. Results show the benefit of using special low-torque DSSV designs under certain operating conditions.

Commentary by Dr. Valentin Fuster
J. Energy Resour. Technol. 1998;120(1):90-94. doi:10.1115/1.2795017.

Diverter systems, used as a means of well control while drilling surface hole, have a history of occasional failure. This paper addresses excessive back pressure, which can result in mechanical failure of surface equipment or foundation collapse. Flows at critical rates are shown both experimentally and theoretically to have a significant effect on back pressure. Critical flow is modeled by quantifying exit pressures and by including fluid acceleration pressure losses in back-pressure calculations. Experiments were then conducted in 1-in., 2-in., and 5-in. pipes to verify these mathematical models. A “systems analysis” approach was used for the diverter design, which allowed for consideration of wellbore and reservoir performance effects. This procedure allows the relationship of diverter vent line diameter, conductor depth, and drilling depth to be better identified, yielding improved design criteria.

Commentary by Dr. Valentin Fuster

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