GAS DISPLACEMENT: AN IMPORTANT CONTROL ON OIL AND GAS DISTRIBUTION IN THE TIMOR SEA?

1997 ◽  
Vol 37 (1) ◽  
pp. 259 ◽  
Author(s):  
M. Lisle ◽  
G. W. O'Brien ◽  
M. P. Brincat
Keyword(s):  
Oil And Gas ◽  
Dew Point ◽  
Oil Accumulation ◽  
Gaseous Hydrocarbon ◽  
Fault Block ◽  
Point Pressure ◽  
Timor Sea ◽  
Original Oil In Place ◽  
Dew Point Pressure ◽  
Gas Fields

A study of gas fields in the Timor Sea has shown that these traps often contain palaeo-oil columns, with a high abundance of oil bearing fluid inclusions recorded in sands which are presently gas saturated. These palaeo- oil columns are substantial, suggesting the volume of liquid hydrocarbons that has been redistributed is significant. This remobilised oil in effect constitutes an oil charge of known volume for nearby structures, with seismic mapping confidently allowing the recognition of remigration fairways into up-dip traps. For example, at Oliver-1, a 115 m relict oil column, equating to original oil in place of over 166 MMBBL, has been identified. However, estimates of current oil in place account for less than 45 MMBBL, suggesting that more than 120 MMBBL of oil has been displaced across the spill point of the Oliver structure. Remigration of this oil can be mapped into an adjacent fault block, representing a new exploration play. Significantly, the likelihood of this untested trap containing liquids is supported by the presence of an oil leg at Oliver-1, which shows that only oil has been displaced from the Oliver trap.At Keeling-1, a smaller palaeo-oil accumulation has been detected which equates to about 14 MMBBL originally in place. However, the mechanisms responsible for the passage from palaeo-oil accumulation to the present gaseous hydrocarbon phase are often complex and decisions regarding a potential oil leg need be made judiciously. For example, at Keeling-1, oil shows and hydrocarbon related diagenesis in the overlying section provide compelling evidence that oil was lost due to fault breach rather than gas displacement.In contrast, a lack of evidence for palaeo-oil accumulation at Sunrise-1 and Troubadour-1 is also significant, as it removes the potential for an oil leg displaced either down-dip within the same structure or as a remigrated oil charge to adjacent up-dip structures. Significantly, these fields presently contain condensate and would have existed as separate oil and gas legs if charge occurred before dew point pressure was reached. The absence of a palaeo-oil column implies that the traps were charged after formation pressures exceeded the dew point of the reservoired gas. At Troubadoirr-1, this observation constrains the time of charge to the last 5-10 Ma, when pressures within the trap are estimated to have reached dew point.

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.

scholarly journals Unsteady-state conditions of producing wells at of the Urengoy oil and gas condensate field influences their efficiency

2019 ◽  
pp. 47-53
Author(s):  
Vladislav V. Inyakin ◽  
Semen F. Mulyavin ◽  
Igor A. Usachev
Keyword(s):  
Oil And Gas ◽  
Gas Condensate ◽  
Dew Point ◽  
Unsteady State ◽  
Pressure Drops ◽  
Well Efficiency ◽  
Point Pressure ◽  
Dew Point Pressure ◽  
Liquid Condensate ◽  
Bottomhole Pressure

The development of oil and gas condensate fields is accompanied by phase transformations of reservoir mixtures, i.e. the when the bottomhole pressure drops below the dew point pressure, the liquid condensate becomes versatile and enters the gas phase. Retrograde condensate leads to a decrease in phase permeability in the bottomhole. As a result, it also leads to a decrease in production levels is reduced both by gas and natural gas liquids. The article considers this challenge and its possible solutions by the method of unsteady-state conditions well efficiency, on which the hydraulic fracturing was carried out. The issue of well efficiency is urgent in conditions abnormally high reservoir pressure and considerable condensate yield.

A Comparative Analysis of the Prediction of Gas Condensate Dew Point Pressure Using Advanced Machine Learning Algorithms

2021 ◽  
Author(s):  
Thitaree Lertliangchai ◽  
Birol Dindoruk ◽  
Ligang Lu ◽  
Xi Yang
Keyword(s):  
Machine Learning ◽  
Domain Knowledge ◽  
Compositional Data ◽  
Machine Learning Algorithms ◽  
Empirical Correlation ◽  
Dew Point ◽  
Pvt Data ◽  
Point Pressure ◽  
Input Variables ◽  
Dew Point Pressure

Abstract Dew point pressure (DPP) is a key variable that may be needed to predict the condensate to gas ratio behavior of a reservoir along with some production/completion related issues and calibrate/constrain the EOS models for integrated modeling. However, DPP is a challenging property in terms of its predictability. Recognizing the complexities, we present a state-of-the-art method for DPP prediction using advanced machine learning (ML) techniques. We compare the outcomes of our methodology with that of published empirical correlation-based approaches on two datasets with small sizes and different inputs. Our ML method noticeably outperforms the correlation-based predictors while also showing its flexibility and robustness even with small training datasets provided various classes of fluids are represented within the datasets. We have collected the condensate PVT data from public domain resources and GeoMark RFDBASE containing dew point pressure (the target variable), and the compositional data (mole percentage of each component), temperature, molecular weight (MW), MW and specific gravity (SG) of heptane plus as input variables. Using domain knowledge, before embarking the study, we have extensively checked the measurement quality and the outcomes using statistical techniques. We then apply advanced ML techniques to train predictive models with cross-validation to avoid overfitting the models to the small datasets. We compare our models against the best published DDP predictors with empirical correlation-based techniques. For fair comparisons, the correlation-based predictors are also trained using the underlying datasets. In order to improve the outcomes and using the generalized input data, pseudo-critical properties and artificial proxy features are also employed.

The Effect of Capillary Condensation on the Geomechanical and Acoustic Properties of Tight Formations: An Experimental Study

2021 ◽  
Author(s):  
Aamer Albannay ◽  
Binh Bui ◽  
Daisuke Katsuki
Keyword(s):  
Pore Pressure ◽  
Capillary Condensation ◽  
Pore Space ◽  
Dew Point ◽  
Acoustic Properties ◽  
Point Pressure ◽  
Tight Formations ◽  
Dew Point Pressure ◽  
Compressional Velocity

Abstract Capillary condensation is the condensation of the gas inside nano-pore space at a pressure lower than the bulk dew point pressure as the result of multilayer adsorption due to the high capillary pressure inside the small pore throat of unconventional rocks. The condensation of liquid in nano-pore space of rock changes its mechanical and acoustic properties. Acoustic properties variation due to capillary condensation provides us a tool to monitor phase change in reservoir as a result of nano-confinement as well as mapping the area where phase change occurs as well as characterize pore size distribution. This is particularly important for tight formations where confinement has a strong effect on phase behavior that is challenging to measure experimentally. Theoretical studies have examined the effects of capillary condensation; however, these findings have not been verified experimentally. The main objective of this study is to experimentally investigate the effect of capillary condensation on the mechanical and acoustic properties of shale samples. The mechanical and acoustic characterization of the samples was carried out experimentally using a state-of-the-art tri-axial facility at the Colorado School of Mines. The experimental set-up is capable of the simultaneous acquisition of coupled stress, strain, resistivity, acoustic and flow data. Carbon dioxide was used as the pore pressure fluid in these experiments. After a comprehensive characterization of shale samples, experiments were conducted by increasing the pore pressure until condensation occurs while monitoring the mechanical and acoustic properties of the sample to quantify the effect of capillary condensation on the mechanical and acoustic properties of the sample. Experimental data show a 5% increase in Young's Modulus as condensation occurs. This increase is attributed to the increase in pore stiffness as condensation occurs reinforcing the grain contact. An initial decrease in compressional velocity was observed as pore pressure increases before condensation occurs which is attributed to the expansion of the pore volume when pore pressure increases. After this initial decrease, compressional velocity slightly increases at a pressure around 750 - 800 psi which is close to the condensation pressure. We also observed a noticeable increase in shear velocity when capillary condensation occurs, this could be due to the immobility of the condensed liquid phase at the pore throats. The changes of geomechanical and acoustic signatures were observed at around 750 - 800 psi at 27°C, which is the dew point pressure of the fluid in the nano-pore space of the sample at this temperature. While the unconfined bulk dew point pressure of carbon dioxide at the same temperature is 977 psi. Hence, this study marks the first measurement of the dew point of fluid in nano-pore space and potentially leads to the construction of the phase envelope of fluid under confinement.

Predicting Dew Point Pressure: Using a Hybrid Intelligent Network

2014 ◽  
Vol 32 (24) ◽  
pp. 2969-2975 ◽  
Author(s):  
Sh. Ghassemzadeh ◽  
M. Schaffie ◽  
A. Sarrafi ◽  
M. Ranjbar
Keyword(s):  
Dew Point ◽  
Intelligent Network ◽  
Point Pressure ◽  
Dew Point Pressure

THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 405 ◽  
Author(s):  
C.W. Luxton ◽  
S. T. Horan ◽  
D.L. Pickavance ◽  
M.S. Durham.
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Production Test ◽  
Water Contact ◽  
Excellent Quality ◽  
Fault Block ◽  
Well Location ◽  
Gas Fields

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.

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