Mass transfer studies in oil-containing multiphase flow provide fundamental knowledge towards the understanding of hydrodynamics and the subsequent effect on corrosion in pipelines. Mass transfer coefficient measurements in two-phase (oil/ferri-ferrocyanide) and three-phase (oil/ferri-ferrocyanide/nitrogen) flow using limiting current density technique were made in 10-cm-dia pipe at 25 and 75 percent oil percentage. Mass transfer coefficients in full pipe oil/water flow and slug flow were studied. A relationship is developed between the average mass transfer coefficient in full pipe flow and slug flow. The mass transfer coefficient decreased with a decrease of in-situ water cut. This was due to the existence of oil phase, which decreased the ionic mass transfer diffusion coefficient.
In spite of the sand control/management techniques implemented down-hole, fine sand (< 50-75 microns) often may find its way into the piping components of onshore, offshore, and subsea facilities causing erosion/wear and subsequent pipeline integrity issues. Existing erosion models (both CFD-based and correlations) widely used in the industry have been reasonably benchmarked with erosion due to sand particles that are greater than 100-150 microns and the predictions are within ±100% of observations even in single-phase carrier (liquid or gas) flows. Although there is only a limited set of the fines erosion data (both lab and field), there is a considerable mismatch between the data and what the models predict even when the fines (< 50 microns) are carried in single-phase (let alone multiphase) fluid flow. Also, current industry practice is to assume that the low liquid content of gas stream reduces fines erosion by forming a protective film on the pipe wall although there is no clear understanding on what fraction of the liquid content (a) gets atomized into droplets (that may or may not wet the fine particles) in the gas stream and (b) wets the pipe wall. Even the development and validation efforts of the correlations for fine particle-pipe wall interaction leading to a single erosion event (let alone CFD-based erosion simulation) are still at their infancy. Several renowned erosion research groups around the world have been working on addressing the afore-said gaps. New fines erosion experiments were conducted in a 4" flow facility that consists of several piping components (orifice plates, elbows, and tees) that were connected in series and pipe wall thickness loss due to erosion was measured using a standard ultrasonic method. This paper elucidates the effect of (a) interaction of piping components connected in series (in-plane and out-of-plane) and (b) effect of low liquid loading in gas on fines erosion, scaleup to field conditions, and provides some directions for future efforts needed on this topic that are critical to the safe and efficient operation of oil-gas producing/processing facilities.
Presently, several large deep water natural gas fields are designed to produce over 1000 MMSCFD of gas with low liquid content <20 BBL/MMSCF. Such deep water facilities are typically comprised of ~8-10" diameter well manifolds and 30-40" in diameter 100 mile long flow lines that are operated at high pressure and temperature conditions. Key CAPEX and OPEX decisions for deep water gas facilities include: wellbore tubing and subsea flow line sizing, subsea flow line routing, pigging frequency, pipeline materials, range of allowable operating rates and large production rate variations, and subsea asset integrity management. Key design decisions require knowledge of variations in flow regime over field life, liquid hold-up in the flow lines, liquid entrainment and sand in the fluids in the subsea facilities that may result in erosion at the high operating limit and sand deposition concerns at low operating limit. Given the scarcity of data at conditions similar to wet gas field conditions, current industry-standard multiphase flow simulators predict flow behaviors with a high degree of uncertainty and hence, are known to have been inadequately validated. This paper presents a unique set of high quality wet gas multiphase flow data in a 16" diameter flow loop operated at ambient conditions including several salient measurements such as pressure drop, liquid hold-up, liquid film velocity as a function of liquid film depth, average liquid film velocity, etc. using state-of-the-art instrumentation.
Experiments have been carried out in a 36-m long, 10-cm diameter multiphase horizontal flow system to examine the effect of drag reducing agents (DRA) on average pressure drop, maximum pressure drop and slug characteristics with the presence of water. Superficial liquid velocities between 0.5 and 1.5 m/s and superficial gas velocities between 2 and 14 m/s were investigated. Oil with a viscosity of 2.5 cP at 25 °C was used for the study. ASTM salt was used as a substitute for seawater and carbon dioxide was used as the gas. Water cut was 50%. Temperature and pressure were maintained at 25 °C and 0.13 MPa. The DRA concentrations of 0, 20 and 50 ppm were used in this study. The results show that the average pressure drop in both slug flow and annular flow decreased significantly with addition of DRA. Under special conditions, it was found that DRA changed the flow pattern from pseudo-slug to annular resulting in a 74% reduction in pressure drop. For annular flow, the average pressure drop reduction of up to 53% was achieved. The maximum pressure drop across the slug also decreased with the presence of DRA. The average and maximum pressure drops at a DRA concentration of 50 ppm were more effective than 20 ppm for all cases. The slug frequency and effective height of the liquid film decreased significantly when DRA concentrations were added. This led to a decrease in the average pressure drop. However, the slug translational velocity did not change significantly with addition of DRA.
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