The Effect of Nitrogen on Reservoir Fluid Saturation Pressure

1967 ◽  
Vol 6 (03) ◽  
pp. 101-105 ◽  
Author(s):  
H.A. Jacobson
Keyword(s):  
Saturation Pressure ◽  
Fluid Saturation ◽  
Reservoir Fluid

Effect of Dilution on Acoustic and Transport Properties of Reservoir Fluid Systems and Their Interplay

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 2867-2880
Author(s):  
Ram R. Ratnakar ◽  
Edward J. Lewis ◽  
Birol Dindoruk
Keyword(s):  
Measurement Techniques ◽  
Saturation Pressure ◽  
Ultrasonic Pulse ◽  
Acoustic Velocity ◽  
Viscosity Data ◽  
Reservoir Fluid ◽  
Fluid Systems ◽  
Fluid Properties ◽  
Volume Measurements ◽  
Live Oil

Summary Acoustic velocity is one of the key thermodynamic properties that can supplement phase behavior or pressure/volume/temperature (PVT) measurements of pure substances and mixtures. Several important fluid properties are relatively difficult to obtain through traditional measurement techniques, correlations, or equation of state (EOS) models. Acoustic measurements offer a simpler method to obtain some of these properties. In this work, we used an experimental method based on ultrasonic pulse-echo measurements in a high-pressure/high-temperature (HP/HT) cell to estimate acoustic velocity in fluid mixtures. We used this technique to estimate related key PVT parameters (such as compressibility), thereby bridging gaps in essential data. In particular, the effect of dilution with methane (CH4) and carbon dioxide (CO2) at pressures from 15 to 62 MPa and temperatures from 313 to 344 K is studied for two reservoir fluid systems to capture the effect of the gas/oil ratio (GOR) and density variations on measured viscosity and acoustic velocity. Correlative analysis of the acoustic velocity and viscosity data were then performed to develop an empirical correlation that is a function of GOR. Such a correlation can be useful for improving the interpretation of the sonic velocity response and the calibration of viscosity changes when areal fluid properties vary with GOR, especially in disequilibrium systems. In addition, under isothermal conditions, the acoustic velocity of a live oil decreases monotonically with decreasing pressure until the saturation point where the trend is reversed. This observation can also be used as a technique to estimate the saturation pressure of a live oil or as a byproduct of the target experiments. It supplements the classical pressure/volume measurements to determine the bubblepoint pressure.

Reservoir-Fluid Sampling Revisited - A Practical Perspective

2007 ◽  
Vol 10 (06) ◽  
pp. 589-596 ◽  
Author(s):  
Johannes Bon ◽  
Hemanta Kumar Sarma ◽  
Jose Teofilo Rodrigues ◽  
Jan Gerardus Bon
Keyword(s):  
Oil Recovery ◽  
Economic Value ◽  
Saturation Pressure ◽  
Sulfur Compounds ◽  
Second Phase ◽  
Plant Design ◽  
Reservoir Fluid ◽  
Well Conditioning ◽  
Sampling Procedures ◽  
Fluid Sampling

Summary Pressure/volume/temperature (PVT) fluid properties are an integral part of determining the ultimate oil recovery and characterization of a reservoir, and are a vital tool in our attempts to enhance the reservoir's productive capability. However, as the experimental procedures to obtain these are time consuming and expensive, they are often based on analyses of a few reservoir-fluid samples, which are then applied to the entire reservoir. Therefore, it is of utmost importance to ensure that representative samples are taken, as they are fundamental to the reliability and accuracy of a study. Critical to the successful sampling of a reservoir fluid is the correct employment of sampling procedures and well conditioning before and during sampling. There are two general methods of sampling—surface and subsurface sampling. However, within these, there exist different methods that can be more applicable to a particular type of reservoir fluid than to another. In addition, well conditioning can differ depending on the type of reservoir fluid. Sampling methods for each reservoir type will be discussed with an emphasis on scenarios where difficulties arise, such as near-critical reservoir fluids and saturated reservoirs. Methods, including single-phase sampling and isokinetic sampling, which have been used increasingly in the last decade, will also be discussed with some detail, as will preservation of the representatives of other components in the sample including asphaltenes, mercury, and sulfur compounds. The paper presents a discussion aimed at better understanding the methods available, concepts behind the methods, well conditioning, and problems involved in obtaining representative fluid samples. Introduction Reservoir-fluid samples are obtained for a number of reasons, includingPVT analysis for subsequent engineering calculationsDetermination of the components that exist in a particular reservoir to have an understanding of the economic value of the fluidKnowledge of the contents of certain components that exist in the reservoir fluid for further planning and future drilling programs, such as the content of sulfur compounds and carbon dioxide, and the corrosiveness of the fluid. This will have an impact on the material used for casing, tubing, and surface equipment that may be necessaryKnowledge of the fluid's ability to flow through production tubing, pipelines, and other flow lines, and possible problems that may arise because of viscosity changes because of precipitation of solids such as wax and/or of asphalteneDetermining the contaminating components that affect plant design, such as the mercury content, sulfur components, and radioactive componentsIf the saturation pressure is approximately equal to the reservoir pressure then a second phase may be present. This is particularly relevant for gas reservoirs, where further drilling may discover an oil or condensate leg. Mostly the samples are required to obtain a better knowledge of a combination of these effects; however, it must be kept in mind that often the sample is not required to resolve all of these issues.

REAL-TIME AND ON-SITE RESERVOIR FLUID CHARACTERISATION USING SPECTRAL ANALYSIS AND PVT EXPRESS

2004 ◽  
Vol 44 (1) ◽  
pp. 605
Author(s):  
A.K.M. Jamaluddin ◽  
C. Dong ◽  
P. Hermans ◽  
I.A. Khan ◽  
A. Carnegie ◽  
...  
Keyword(s):  
Real Time ◽  
Carbon Number ◽  
Saturation Pressure ◽  
Fluid Composition ◽  
Reservoir Fluid ◽  
Basic Fluid ◽  
Development Cycle ◽  
Surface Analysis Techniques ◽  
Fluid Properties ◽  
Open Hole

Obtaining an adequate fluid characterisation early in the life of a reservoir is becoming a key requirement for successful hydrocarbon development. This work presents and discusses a number of new fluid sampling and fluid characterisation technologies that can be deployed either down hole or at surface in the early stages of the exploration and development cycle to achieve this objective. Techniques discussed include methods to monitor and quantify oil-based mud contamination, gas-liquid-ratio (GLR) and basic fluid composition in real time during open-hole formation testing operations. In addition, we demonstrate the applicability of new surface analysis techniques that allow for rapid, accurate, and reliable measurements of key fluid properties, such as saturation pressure, gas-oil ratio, extended carbon number composition, viscosity, and density, on-site within a few hours of retrieving reservoir fluid samples at surface. Finally, prediction tools used to extend these limited measurements to a traditional PVT fluid characterisation are presented along with example measurements from all the techniques described. In conclusion, it is shown that the implementation of these techniques in a complementary program can reduce the risk associated with making key development decisions that are based on an understanding of reservoir fluid properties.

DEEP TRANSIENT TESTING DIGITAL PRODUCTS CREATE NOVEL REAL-TIME RESERVOIR INSIGHTS

2021 ◽  
Author(s):  
Jansen Oliveira ◽  
◽  
Karl Perez H. ◽  
Alejandro Martin V. ◽  
Ricard Fernandez T. ◽  
...  
Keyword(s):  
Numerical Analysis ◽  
Real Time ◽  
History Matching ◽  
Fluid Model ◽  
Saturation Pressure ◽  
Fluid Composition ◽  
Dynamic Data ◽  
Pressure Transient ◽  
Reservoir Fluid ◽  
Geologic Model

Offshore exploration requires the evaluation of hydrocarbon presence, estimation of volumes in place, and flow potential. To this capacity, formation testers are widely used to determine static data such as reservoir fluid gradients and reservoir pressure, obtain fluid samples, and to assess reservoir connectivity. Dynamic data, acquired with interval pressure transient testing and well testing techniques, are used to assess reserves and productivity. However, these evaluation techniques provide dynamic data at different resolution and length scales, and with different environmental footprint, cost, and operational constraints. A new wireline formation testing technique known as deep transient testing (DTT) has been introduced, which combines high-resolution measurements, higher flow rates, and longer test durations to perform transient tests in higher permeability, thicker formation, and at greater depth of investigation than with previous formation testers—without flaring and at a low carbon footprint. The platform combines advanced metrology with extensive automation to generate unique, real-time reservoir insights. Traditionally, pressure transient analysis and well deliverability predictions were produced through an analytical framework. Today, deep transient testing measurements are interpreted, and placed in reservoir context, in real-time by integration with geological and reservoir models. These steps can be performed from any wellsite utilizing cloud-based resources. Products such as reservoir fluid compressibility, saturation pressure, equation of state (EOS) models, well productivity, or minimum connected volumes are integrated in real-time interpretation utilizing numerical analysis. The digital infrastructure enables key reservoir insights to be shared between all stakeholders in a transparent and collaborative environment for both operational control and rapid decision making. This paper presents a case study where the new DTT technique was combined with numerical analysis and real-time integrated workflows to characterize a multilayer reservoir in a recent discovery in deepwater Mexico. During the drawdown phase of the DTT operation, real-time downhole fluid analysis was used to determine the fluid composition, density, viscosity, compressibility, and saturation pressure. These fluid properties were then used to generate and tune an EOS model. Accurate drawdown flow rate measurements and the subsequent pressure transients were combined with the fluid model and geologic model to enable integrated pressure transient history matching. The resulting calibrated numerical model honors the fluid measurements and geologic model and was used to predict the permeability profile, zonal producibility, and the volume of influence of the test.

scholarly journals Pressure and fluid saturation prediction in a multicomponent reservoir using combined seismic and electromagnetic imaging

Geophysics ◽  
2003 ◽  
Vol 68 (5) ◽  
pp. 1580-1591 ◽  
Author(s):  
G. Michael Hoversten ◽  
Roland Gritto ◽  
John Washbourne ◽  
Tom Daley
Keyword(s):  
Electrical Conductivity ◽  
Water Saturation ◽  
Saturation Pressure ◽  
Shear Velocity ◽  
Velocity Shear ◽  
Rock Properties ◽  
Velocity Change ◽  
Archie’S Law ◽  
Fluid Saturation ◽  
Compressional Velocity

This paper presents a method for combining seismic and electromagnetic (EM) measurements to predict changes in water saturation, pressure, and CO2 gas/oil ratio in a reservoir undergoing CO2 flood. Crosswell seismic and EM data sets taken before and during CO2 flooding of an oil reservoir are inverted to produce crosswell images of the change in compressional velocity, shear velocity, and electrical conductivity during a CO2 injection pilot study. A rock‐properties model is developed using measured log porosity, fluid saturations, pressure, temperature, bulk density, sonic velocity, and electrical conductivity. The parameters of the rock‐properties model are found by an L1‐norm simplex minimization of predicted and observed differences in compressional velocity and density. A separate minimization, using Archie's law, provides parameters for modeling the relations between water saturation, porosity, and electrical conductivity. The rock‐properties model is used to generate relationships between changes in geophysical parameters and changes in reservoir parameters. Electrical conductivity changes are directly mapped to changes in water saturation; estimated changes in water saturation are used along with the observed changes in shear‐wave velocity to predict changes in reservoir pressure. The estimation of the spatial extent and amount of CO2 relies on first removing the effects of the water saturation and pressure changes from the observed compressional velocity changes, producing a residual compressional velocity change. This velocity change is then interpreted in terms of increases in the CO2/oil ratio. Resulting images of the CO2/oil ratio show CO2‐rich zones that are well correlated to the location of injection perforations, with the size of these zones also correlating to the amount of injected CO2. The images produced by this process are better correlated to the location and amount of injected CO2 than are any of the individual images of change in geophysical parameters.

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