Assessment of Individual Skin Factors in Gas Condensate and Volatile Oil Wells

Abstract Bubble-point and dew-point pressures of oil and gas condensate reservoir fluids are used for planning the production profile of these reservoirs. Usually the best method for determination of these saturation pressures is by visual observation when a Constant Mass Expansion (CME) test is performed on a sample in a high pressure cell fitted with a glass window. In this test the cell pressure is reduced in steps and the pressure at which the first sign of gas bubbles is observed is recorded as bubble-point pressure for the oil samples and the first sign of liquid droplets is recorded as the dew-point pressure for the gas condensate samples. The experimental determination of saturation pressure especially for volatile oil and gas condensate require many small pressure reduction steps which make the observation method tedious, time consuming and expensive. In this study we have extended the Y-function which is often used to smooth out CME data for black oils below the bubble-point to determine saturation pressure of reservoir fluids. We started from the initial measured pressure and volume and by plotting log of the extended Y function which we call the YEXT function, with the corresponding pressure, two straight lines were obtained; one in the single phase region and the other in the two phase region. The point at which these two lines intersect is the saturation pressure. The differences between the saturation pressures determined by our proposed YEXT function method and the observation method was less than ± 4.0 % for the gas condensate, black oil and volatile oil samples studied. This extension of the Y function to determine dew-point and bubble-point pressures was not found elsewhere in the open literature. With this graphical method the determination of saturation pressures is less tedious and time consuming and expensive windowed cells are not required.

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

10.2118/205742-ms ◽

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.

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Modelling Multiphase Flows of Hydrocarbons in Gas-Condensate and Oil Wells

Mathematical Models and Computer Simulations ◽

10.1134/s2070048220060162 ◽

2020 ◽

Vol 12 (6) ◽

pp. 1005-1013

Author(s):

E. V. Usov ◽

V. N. Ulyanov ◽

A. A. Butov ◽

V. I. Chuhno ◽

P. A. Lyhin

Keyword(s):

Multiphase Flows ◽

Oil Wells ◽

Gas Condensate

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A Novel Chemical Treatment to Enhance Productivity of Volatile Oil Wells

10.2118/138124-ms ◽

2010 ◽

Cited By ~ 4

Author(s):

David Enrique Torres ◽

Mukul Mani Sharma ◽

Gary Arnold Pope ◽

Mohabbat Ahmadi ◽

Corey Alan McCulley ◽

...

Keyword(s):

Chemical Treatment ◽

Volatile Oil ◽

Oil Wells

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An Equation of State Compositional Model

Society of Petroleum Engineers Journal ◽

10.2118/8284-pa ◽

1980 ◽

Vol 20 (05) ◽

pp. 363-376 ◽

Cited By ~ 151

Author(s):

Keith H. Coats

Keyword(s):

Equation Of State ◽

Critical Point ◽

Oil And Gas ◽

Numerical Models ◽

Volatile Oil ◽

Gas Condensate ◽

Numerical Dispersion ◽

Stable Convergence ◽

Compositional Model ◽

Miscible Flooding

Abstract This paper describes an implicit, three-dimensional formulation for simulating compositional-type reservoir problems. The model treats three-phase flow in Cartesian (x-y-z) or cylindrical (r-theta-z) geometries. Applicability ranges from depletion or cycling of volatile oil and gas condensate to miscible flooding operations involving either outright or multicontact-miscibility.The formulation uses an equation of state for phase equilibrium and property calculations. The equation of state provides consistency and smoothness as gas- and oil-phase compositions and properties converge near a critical point. This avoids computational problems near a critical point associated with use of different correlations for K values as opposed to phase densities. Computational testing with example multicontact-miscibility (MCM) problems indicates stable convergence of this formulation as phase properties converge at a critical point. Results for these MCM problems show significant numerical dispersion, primarily affecting the calculated velocity of the miscible-front advance. Our continuing effort is directed toward reduction of this numerical disperson and comparison of model results with laboratory experiments for both MCM and outright-miscibility cases.We feel that the implicit nature of the model enhances efficiency as well as reliability for most compositional-type problems. However, while we report detailed problem results and associated computing times, we lack similar reported times to compare the overall efficiency of an implicit compositional formulation with that of a semi-implicit formulation. Introduction Many papers have treated increasingly sophisticated or efficient methods for numerical modeling of black-oil reservoir performance. That type of reservoir allows an assumption that reservoir gas and oil have different but fixed compositions, with the solubility of gas in oil being dependent on pressure alone.A smaller number of papers have presented numerical models for simulating isothermal "compositional" reservoirs, where oil and gas equilibrium compositions vary considerably with spatial position and time. With some simplification, the reservoir problems requiring compositional treatment can be divided into two types. The first type is depletion and/or cycling of volatile oil and gas condensate reservoirs. The second type is miscible flooding with MCM generated in situ.A distinction between these types is that the first usually involves phase compositions removed from the critical point, while the second type generally requires calculation of phase compositions and properties converging at the critical point. A compositional model should be capable of treating the additional problem of outright miscibility where the original oil and injected fluid are miscible on first contact.A difficulty in modeling the MCM process is achievement of consistent, stable convergence of gas-and oil-phase compositions, densities, and viscosities as the critical point is approached. A number of studies have reported models that use different correlations for equilibrium K-values as opposed to phase densities. Use of an equation of state offers the advantage of a single, consistent source of calculated K-values, phase densities, and their densities near a critical point. SPEJ P. 363＾

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Features of the geological structure of an oil and gas condensate field in Tomsk region

Oil and Gas Studies ◽

10.31660/0445-0108-2021-4-48-60 ◽

2021 ◽

pp. 48-60

Author(s):

S. F. Mulyavin ◽

A. V. Byakov ◽

R. A. Neschadimov

Keyword(s):

Oil And Gas ◽

Phase State ◽

Volatile Oil ◽

Geological Structure ◽

Gas Condensate ◽

Gas Content ◽

Oil Viscosity ◽

Coastal Marine ◽

Tomsk Region ◽

Continental Origin

The X oil and gas condensate field is located in Parabel district of Tomsk region; the field is large in terms of recoverable reserves. Oil and gas content is confined to Jurassic sediments of Tyumen suite and Vasyugan suite. The reservoirs of the Vasyugan suite are marine and coastal-marine sediments, characterized by alternating sandstones, mudstones, siltstones, clays and exhibit complex internal aging. The productive deposits of the Tyumen suite are of continental origin and are distinguished by significant lithological variability. One oil deposit (J11 stratum), one gas and oil deposit (J12 stratum) and three gas condensate deposits (J13-4, J3, J4-5 strata) were identified in the productive formations. The article analyzes the features of the geological structure and conditions of sedimentation of productive strata. In terms of its phase state and physicochemical proper-ties, the fluid of the J11 deposit is a "volatile oil", phase state of which is close to the near-critical. Reservoirs of productive formations are of terrigenous type, porous, low-permeability, while the oil productivity of the formations is high due to the ultra-low oil viscosity.

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