scholarly journals Productions of volatile oil and gas-condensate from liquid rich shales

2018 ◽  
Vol 3 (1) ◽  
pp. 29-42 ◽  
Author(s):  
Palash Panja ◽  
Manas Pathak ◽  
Milind Deo
Keyword(s):  
Oil And Gas ◽  
Volatile Oil ◽  
Gas Condensate

Determination of Bubble-Point and Dew-Point Pressure Without a Visual Cell

2014 ◽  
Author(s):  
R.. Hosein ◽  
R.. Mayrhoo ◽  
W. D. McCain
Keyword(s):  
Oil And Gas ◽  
Saturation Pressure ◽  
Volatile Oil ◽  
Phase Region ◽  
Gas Condensate ◽  
Dew Point ◽  
Bubble Point ◽  
Point Pressure ◽  
Dew Point Pressure

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.

An Equation of State Compositional Model

1980 ◽  
Vol 20 (05) ◽  
pp. 363-376 ◽  
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＾

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

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.

APPLICATION OF THE BLACK OIL PVT REPRESENTATION TO SIMULATION OF GAS CONDENSATE RESERVOIR PERFORMANCE

1987 ◽  
Vol 27 (1) ◽  
pp. 370
Author(s):  
W.H. Goldthorpe ◽  
J.K. Drohm
Keyword(s):  
Oil And Gas ◽  
Volatile Oil ◽  
Gas Condensate ◽  
Phase Behaviour ◽  
Dew Point ◽  
Pressure Drops ◽  
Gas Condensate Reservoirs ◽  
Reservoir Performance ◽  
Black Oil ◽  
Condensate Reservoir

Special attention must be paid to the generation of PVT parameters when applying conventional black oil reservoir simulators to the modelling of volatile oil and gas-condensate reservoirs. In such reservoirs phase behaviour is an important phenomenon and common approaches to approximating this, via the black oil PVT representation, introduce errors that may result in prediction of incorrect recoveries of surface gas and condensate. Further, determination of production tubing pressure drops for use in such simulators is also prone to errors. These affect the estimation of well potentials and reservoir abandonment pressures.Calculation of black oil PVT parameters by the method of Coats (1985) is shown to be preferred over conventional approaches, although the PVT parameters themselves lose direct physical meaning. It is essential that a properly tuned equation of state be available for use in conjunction with experimental data.Production forecasting based on simulation output requires further processing in order to translate the black oil surface phase fluxes into products such as sales gas, LPG and condensate. For gas-condensate reservoirs, such post-processing of results from the simulation of depletion or cycling above the dew point is valid. In principle it is invalid for cycling below the dew point but in practice it can still provide useful information.

Prediction of Liquid Loading in Gas Condensate and Volatile Oil Wells for Unconventional Reservoirs

2020 ◽  
Author(s):  
Reem Alsadoun ◽  
Mohammad Al Momen ◽  
Hongtao Luo
Keyword(s):  
Production Efficiency ◽  
Oil And Gas ◽  
Theoretical Calculations ◽  
Volatile Oil ◽  
Gas Condensate ◽  
Economic Losses ◽  
Well Performance ◽  
Liquid Loading ◽  
Critical Rate ◽  
Correlation Models

Abstract All producing wells experience reservoir pressure depletion which will ultimately cause production to cease. However, the accumulation of wellbore liquid known as liquid loading can reduce production at a faster rate bringing forward the end of well life. In theory, there are many works written on liquid loading in unconventional wells however, these assumptions are challenged when implemented in the field. The aim of this paper is to investigate the relationship between empirical and mechanistic methods used to determine liquid loading critical rates for volatile oil and gas condensate wells, improving liquid loading forecast workflow for future wells. The study was carried on a wide Pressure, Volume, and Temperature (PVT) window with varying compositions ranging from gas condensate to volatile oils. Wells with liquid loading exhibit sharp drops and fluctuations in production. Due to the wide variation in composition however, correlations used must be varied whilst accounting for both composition and horizontal configuration of the well. Using Nodal Analysis methods, Inflow Performance Relationships (IPR) and Vertical Lift Profile (VLP) curves were created from different correlation models fitted for multiple wells selected for this study to optimize well performance. By combining theoretical analysis and field practices for estimating liquid loading critical rate, the appropriate workflow was determined for the volatile oil and gas condensate wells. When comparing the critical rate for liquid loading calculated from theoretical methods against actual rates seen in the field, an inconsistency was observed between the two values for several wells. By establishing a relationship between field estimate and theoretical calculations, liquid loading was forecasted with greater certainty for varying PVT windows. When the liquid loading rate is determined earlier on, the production efficiency can be improved by deploying unloading measures, increasing the well’s producing life, and ultimately alleviating economic losses. By investigating, we were able to establish a suitable process to predict liquid loading critical rates for volatile oil and gas condensate wells. This workflow can be utilized by production engineers to arrange for liquid loading mitigation increasing well life and improving well economics.

Multiphase Rate-Transient Analysis in Unconventional Reservoirs: Theory and Application

2016 ◽  
Vol 19 (04) ◽  
pp. 553-566 ◽  
Author(s):  
Ilkay Uzun ◽  
Basak Kurtoglu ◽  
Hossein Kazemi
Keyword(s):  
Flow Rate ◽  
Single Phase ◽  
Oil And Gas ◽  
Volatile Oil ◽  
Gas Condensate ◽  
Unconventional Reservoirs ◽  
Eagle Ford ◽  
Linear Flow ◽  
Constant Flow Rate ◽  
Flow Models

Summary In unconventional reservoirs, production data are generally analyzed by use of rate-transient techniques derived from single-phase linear-flow models. Such linear-flow models use rate-normalized pressure, which is pressure drop divided by reservoir-flow rate vs. square root of time. In practice, the well-fluid production includes water, oil, and gas. The oil can be light oil, volatile oil, and gas/condensate as in the Bakken, Eagle Ford, and Barnett, respectively. Thus, single-phase analysis needs modification to account for production of fluid mixtures. In this paper, we present a multiphase-pressure-diffusivity equation to analyze multiphase flow in single- and dual-porosity models of unconventional reservoirs. Our approach is similar to the work presented by Perrine (1956); however, our approach has a theoretical foundation, whereas Perrine (1956) used pragmatic engineering analogy for constant flow rate in vertical wells only. In addition to oil, gas, and formation brine, our method accounts for gas/condensate production, and the flowback of the injected hydraulic-fracturing fluids. Overall, our proposed approach is more comprehensive than the single-phase models but maintains the simplicity of the conventional methods. Our paper includes diagnostic plots of rate-normalized well pressure for light oils and gas/condensates in unconventional reservoirs. Data from two Bakken and two Eagle Ford wells will be presented to demonstrate the usefulness of our approach. In addition to the mathematical analysis of flow-rate and pressure data, we will present the effect of well-stimulation and fluid-lift methods on the flow-rate characteristics of Bakken and Eagle Ford wells.

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