Dynamic Growth of Water Saturation Around Oil Wells With Water Coning-Effect of Transverse Dispersion

2006 ◽  
Author(s):  
Shengkai Duan ◽  
Andrew Kraysztof Wojtanowicz
Keyword(s):  
Water Saturation ◽  
Oil Wells ◽  
Transverse Dispersion ◽  
Water Coning ◽  
Dynamic Growth

Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq

2021 ◽  
Author(s):  
Xueqing Tang ◽  
Ruifeng Wang ◽  
Zhongliang Cheng ◽  
Hui Lu
Keyword(s):  
High Pressure ◽  
Heavy Oil ◽  
Oil Quality ◽  
Oil Wells ◽  
Gas Condensate ◽  
Oil Viscosity ◽  
Foamy Oil ◽  
Artificial Lift ◽  
Water Coning ◽  
The Dead

Abstract Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved. Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.

Segregated production method for oil wells with active water coning

1994 ◽  
Vol 11 (1) ◽  
pp. 21-35 ◽  
Author(s):  
Andrew K. Wojtanowicz ◽  
Hui Xu ◽  
Zaki Bassiouni
Keyword(s):  
Production Method ◽  
Oil Wells ◽  
Water Coning

scholarly journals Logging and Lithostratigraphic Study of the Cenomanian-Santonian Reservoirs of Four Oil Wells MSP1, MSP2, MSP3 and MSP4 of the Margin of San-Pedro (Côte d’Ivoire)

2019 ◽  
pp. 1-21
Author(s):  
Bié Goha René ◽  
Gbangbot Jean-Michel Kouadio ◽  
Diangone Eric, Yao N’Goran Jean-Paul ◽  
Digbéhi Zéli Bruno
Keyword(s):  
Marine Environment ◽  
Cote D'ivoire ◽  
Gamma Ray ◽  
Sedimentary Basin ◽  
Water Saturation ◽  
High Water ◽  
Oil Wells ◽  
Reservoir Characteristics ◽  
San Pedro ◽  
Sandstone Reservoirs

The logging and petrophysical study of four oil wells, MSP1, MSP2, MSP3 and MSP4 from San-Pedro margin of the Ivorian sedimentary basin has made it possible to evaluate the reservoir characteristics of the Cenomanian-Santonian age formations. Lithostratigraphically, this study has shown that this interval consists of clay and sandstone deposits interspersed with frequent past carbonate. At the logging, ten (10) sandstone reservoirs are highlighted with effective porosities ranging from 16% to 21% and permeabilities from 100 mD to 1100 mD (millidarcy). These reservoirs have very good petrophysical characteristics however their high water saturation show that they are rather aquifers. The various log gamma ray profiles of the intervals considered highlight a fluvial and marine deposition environment. Sedimentation would have started in a Cenomanian-type fluvial environment and would have continued in a marine environment marked by the accumulation of sandstone and clay under the influence of transgression and regression phases in the Turonian and Lower Senonian.

Theoretical and Experimental Investigation of Water-in-Oil Transverse Dispersion in Porous Media

2010 ◽  
Vol 13 (03) ◽  
pp. 423-437
Author(s):  
Shengkai Duan ◽  
Andrew K. Wojtanowicz
Keyword(s):  
Porous Media ◽  
Transition Zone ◽  
Water Saturation ◽  
Estimation Procedure ◽  
Nonlinear Flow ◽  
Interface Instability ◽  
Two Phase ◽  
Two Fluids ◽  
Transverse Dispersion ◽  
Segregated Flow

Summary Water production is controlled by the size and distribution of water saturation around wells. A recent discovery shows that not employing hydrodynamic mixing in numerical simulators may underestimate the water transition zone (Duan and Wojtanowicz 2006). This paper reports continuing research into mechanisms causing expansion of the water-saturation transition zone (transverse dispersion) in a segregated flow of oil and water approaching a vertical well's completion. The mechanisms—including nonlinear flow, turbulence, shear rate, and flow baffling at grains—all contribute to the instability of the oil/water interface, resulting in hydrodynamic mixing. Interface instability because of shearing rate has been demonstrated in our recent study on the Hele-Shaw model (Duan and Wojtanowicz 2007). In this paper, we mathematically model the effect of flow baffling and demonstrate transverse dispersion experimentally using a linear physical sandpack. A simple model of tortuous flow was developed to demonstrate the effect of two-phase-flow baffling in granular porous media. The model shows that the change in flow momentum of the two fluids at the point of collision with rock grains becomes the major factor causing water dispersion. A series of segregated-flow runs (top, oil; bottom, water) was carried out using a physical model packed with different porous media at a constant pressure drop. The runs were videotaped and analyzed for saturation distribution using a color-intensity-recognition software. The results clearly demonstrate onset of transverse dispersion of water into the flowing oil. Further dispersion, however, was overshadowed by the dimensional and end-point effects of the model. With a numerical estimation procedure, the initial dispersion rate—computed from the 1D flow model—is the essential data needed to estimate total dispersion in radial inflow to wells.

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