Profiling and quantifying complex multiphase flow

Oilfield Review

Volumn 16, Issue 3, 2004, Pages 4-13

  Baldauff, John ^a   Runge, Trevor ^a   Cadenhead, John ^b   Faur, Marian ^b   Marcus, Remi ^b   Mas, Cholid ^b   North, Rob ^b   Oddie, Gary ^b  

^a Gulf of Suez Petroleum Co   (Egypt)

^b NONE

Author keywords

[No Author keywords available]

Indexed keywords

BUBBLE FORMATION; COMPUTATIONAL FLUID DYNAMICS; COMPUTER SIMULATION; DATA ACQUISITION; DISPERSIONS; HARDWARE; HORIZONTAL WELLS; NATURAL RESOURCES EXPLORATION; OIL FIELDS; OPTIMIZATION; PRODUCT DESIGN; PROFILOMETRY; REFRACTIVE INDEX; THERMAL STRATIFICATION; VISCOSITY OF LIQUIDS; WELL LOGGING;

DISPERSED BUBBLE FLOW; PHASE STRATIFICATION; PLUG FLOW; SLUG FLOW;

MULTIPHASE FLOW;

EID: 10044274448     PISSN: 09231730     EISSN: None     Source Type: Journal    
DOI: None     Document Type: Review

References (11)

1. Bamforth S, Besson C, Stephenson K, Whittaker C, Brown G, Catala G, Rouault G, Théron B, Conort G, Lenn C and Roscoe B: "Revitalizing Production Logging," Oilfield Review B. no. 4 (Winter 1996): 44-60.
2. Catala G, Théron B, Conort G and Ferguson J: "Fluid Flow Fundamentals," Oilfield Reviews, no. 4 (Winter 1996): 61-64.
3. Holdup is the area fraction of the pipe occupied by each phase in multiphase flow.
4. "Complex Flows in Nonvertical Wells Pose Logging-Tool Challenges," Journal of Petroleum Technology, 54, no. 4 (April 2004): 26-27.
5. Slip occurs in multiphase flow when one phase flows faster than another phase, or, in other words, slips past it. Because of this phenomenon, there is a difference between the holdups (area fractions) and cuts (volume flow rates) of the phases.
6. In deviated wells at low to medium flow rates, the lighter phase travels along the high side of the pipe and drags some of the heavy phase along, imparting a shear to the body of flow. This, in turn, generates a local recirculation in the heavier phase. A nonlinear velocity profile then exists from the bottom of the pipe to the top, with fluids traveling fastest along the top and slowest or even downwards on the low side. Under these conditions, the fullbore spinner will average the velocities and register downflow - negative velocity, or sometimes no flow.
7. Akhnoukh R, Leighton J, Bigno Y, Bouroumeau-Fuseau P, Quin E, Catala G, Silipigno L, Hemingway J, Horkowitz J, Hervé X, Whittaker C, Kusaka K, Markel D and Martin A: "Keeping Producing Wells Healthy," Oilfield Review 11, no. 1 (Spring 1999): 30-47.
8. Théron B, Vu-Hoang D, Rezgui F, Catala G, McKeon D and Silipigno L: "Improved Determination of Gas Holdup Using Optical Fiber Sensors," Transactions of the 41st SPWLA Annual Logging Symposium, Dallas, June 4-7, 2000, paper GG.
9. Multipass spinner calibration is a technique for interpreting the results from a spinner flowmeter using several logging runs of the flowmeter over the zone of interest at different speeds, both up and down. Spinner speed is a nearly linear function of the effective velocity of the fluid. Although this function can be measured on surface, it varies with the fluid and the flow pattern, and is most reliably determined in situ. After several passes are made, the function can be calibrated to determine in-situ pitch and threshold values for each spinner. The associated local holdup measurements can be used to discriminate individual pitch and threshold values for each phase. The spinner speed is converted into local phase velocity. The flow rate is determined by multiplying the phase velocity by holdup.
10. Borling DC, Powers BS and Ramadan N: "Water Shut-off Case History Using Through Tubing Bridge Plugs; October Field, Nubia Formation, Gulf of Suez, Egypt," paper SPE 36213, presented at the 7th Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, October 13-16, 1996.
11. A gradiomanometer device measures the average fluid density at different depths to produce a fluid-density log. Knowing the density of the individual phases allows their holdups to be determined, directly in the case of biphasic flow, and in combination with other measurements for three-phase flow. Introduced in the late 1950s, the device measures the pressure difference between two pressure sensors, placed approximately 2 ft [0.6 m] apart. The pressure difference reflects the average fluid density across the well within that depth interval.