Effect of salt and water cuts on hydrate anti-agglomeration in a gas condensate system at high pressure

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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Carbon Dioxide in a Natural Gas-Condensate System

Industrial & Engineering Chemistry ◽

10.1021/ie50437a024 ◽

1946 ◽

Vol 38 (5) ◽

pp. 530-534 ◽

Cited By ~ 1

Author(s):

Fred H. Poettmann ◽

Donald L. Katz

Keyword(s):

Carbon Dioxide ◽

Natural Gas ◽

Gas Condensate ◽

Condensate System

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Extending Well Productive Life with Acid Re-fracturing in a High Pressure/High Temperature Tight Gas/Condensate Carbonate Reservoir

10.2118/142444-ms ◽

2011 ◽

Author(s):

Mir Md. Rezaul Kabir ◽

Qasem M. Dashti ◽

Jai Ram Singh ◽

San Prasad Pradhan ◽

Ikhsan Nugraha ◽

...

Keyword(s):

High Pressure ◽

High Temperature ◽

Carbonate Reservoir ◽

Gas Condensate ◽

Tight Gas ◽

Productive Life ◽

High Pressure High Temperature

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Experimental Determination of Relative Permeabilities for a Rich Gas/Condensate System Using Live Fluid

SPE Reservoir Evaluation & Engineering ◽

10.2118/109810-pa ◽

2009 ◽

Vol 12 (02) ◽

pp. 263-269 ◽

Cited By ~ 9

Author(s):

Jeffrey F. App ◽

Jon E. Burger

Keyword(s):

Steady State ◽

Capillary Number ◽

Single Phase ◽

Gas Condensate ◽

Relative Permeabilities ◽

State Process ◽

Reservoir Fluid ◽

Condensate System ◽

The Impact ◽

Model Fluids

Summary Measurement of gas and condensate relative permeabilities typically is performed through steady-state linear coreflood experiments using model fluids. This study addresses experimental measurement of relative permeabilities for a rich-gas/condensate reservoir using a live, single-phase reservoir fluid. Using a live, single-phase reservoir fluid eliminates the difficulties in designing a relatively simple model fluid that replicates the complicated thermodynamic and transport properties of a near-critical fluid. Two-phase-flow tests were performed across a range of pressures and flow rates to simulate reservoir conditions from initial production through depletion. A single-phase multirate experiment was also performed to assess inertial, or non-Darcy, effects. Correlations were developed to represent both the gas and condensate relative permeabilities as a function of capillary number. A nearly 20-fold increase in gas relative permeability was observed from the low- to high-capillary-number flow regime. Compositional simulations were performed to assess the impact of the experimental results for vertical- and horizontal-well geometries. Introduction Well-deliverability estimates for gas/condensate systems require accurate prediction of both gas and condensate effective permeability. This is particularly important within the near-wellbore region where the pressures often fall below dewpoint causing retrograde condensation. Within this region, pressure gradients in both flowing phases are large and the interfacial tension between the gas and condensate is low. This results in relative permeabilities that are rate sensitive. Under these conditions, both capillary number and non-Darcy effects must be considered in modeling of gas/condensate flows. The relative permeabilities increase with increasing capillary number and are reduced by inertial, or non-Darcy, flow effects. Gas and condensate relative permeabilities are typically determined by steady-state linear coreflood experiments. Numerous experimental studies have been performed demonstrating an improvement in both gas and condensate relative permeability at high velocities and at low interfacial tension (Henderson et al. 1998; Henderson et al. 1997; Ali et al. 1997). These studies used model fluids to represent the reservoir fluid, which generally represented leaner gas/condensate systems. Chen et al. (1995) performed similar experiments using a recombined gas/condensate system from a North Sea field. Proper recombination with surface gas and condensate samples, however, assumes that the correct condensate/gas ratio is known. Using single-phase downhole samples obtained at pressures above the dewpoint eliminates this uncertainty. Fevang and Whitson (1996) have shown that krg for a steady state process is a function of the krg/kro ratio, where the krg/kro ratio is a function of pressure. The dependency of krg on both the capillary number (Nc) and the krg/kro ratio for a pseudosteady-state process has been demonstrated experimentally by Whitson et al. (1999) and Mott et al. (1999). These studies used either model fluids or recombined reservoir fluids with krg/kro ratios primarily within the range of 1 to 90. The lower krg/kro ratios represent richer fluids, while the higher krg/kro ratios represent leaner fluids. The fluids studied in this paper, however, are significantly richer, with krg/kro ratios in the range of 0.05 to 0.15 on the basis of fluid compositions at initial reservoir conditions. Non-Darcy or inertial effects reduce relative permeabilities. This has been demonstrated through linear coreflood experiments by several investigators (Lombard et al. 2000; Henderson et al. 2000; Mott et al. 2000). Multirate non-Darcy single-phase experiments were performed as part of this study because of the anticipated high flow rates from this reservoir. The objectives of this study were (1) to experimentally measure gas and condensate relative permeabilities for a rich gas/condensate system using a live, single-phase reservoir fluid; (2) assess the magnitude of inertial effects through the measurement of the non-Darcy coefficient; and (3) evaluate the impact of the capillary-number-dependent relative permeabilities and non-Darcy effects on the performance of vertical and horizontal wells.

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Studying the impact of carbon dioxide on phase transitions of gas-condensate systems and dispersion of retrograde condensate

Azerbaijan Oil Industry ◽

10.37474/0365-8554/2021-4-17-22 ◽

2021 ◽

pp. 17-22

Author(s):

N.N. Hamidov ◽

◽

Keyword(s):

Carbon Dioxide ◽

Phase Transitions ◽

Gas Phase ◽

Development Process ◽

Gas Condensate ◽

Critical Parameters ◽

Physico Chemical ◽

Retrograde Condensation ◽

Condensate System ◽

The Impact

The paper studies the effect of carbon dioxide on the phase transitions within gas-condensate systems and defines its role on the evaporation of retrograde condensate isolated in formation due to the decreasing pressure during development process. Based on the experiments carried out by special methodology in рVT bomb, the essence of various impact of carbon dioxide amount in the content of gas-condensate mixture on the physico-chemical and thermo-dynamic parameters of the system depending on the temperature interval revealed. As a result of experiments, it was defined that the increase of carbon dioxide within gas-condensate mixture raises the content of dispersed condensate in gas phase. Moreover, the increase of CO2 in gas phase leads to the growth of gas amount dissolved in a unit volume of condensate as well. It is shown that the effect of carbon dioxide on the pressure of retrograde condensation within gas-condensate system cannot be definitely estimated. The pressure of retrograde condensation within such mixtures may be different in various temperature diapasons due to the change of the features and critical parameters of the system.

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