References

What is Cloud Computing?

Sun, 01 Dec 2019 08:00:00 GMT

Cloud computing, also called on-demand computing is a new kind of computation based on the internet. The engineering program or application software, usually needs to be installed on a personal computer to execute the calculations, is now replaced by a server or servers that provide solutions to meet the demand from the customers and the enterprises. The user’s computer, or iPad or cell phone that is networking and given right to access to the server, will be able to perform the calculations, store and process the data, and transfer the tables and the plots as well as accomplish other tasks according to users’ needs. All the required computing resources and the various capabilities are hidden in the “cloud” to provide the services to the users. Cloud computing enables the engineers to run software programs and demonstrate their products and services world wide.

Cloud computing adopts a new business model of “pay as you go" and has become a highly demanded on-line service due to the advantages of high computing performance, cheap cost, high scalability, accessibility as well as availability.

Cloud Computing vs Traditional Software

Cloud Computing

The computation is based on the internet with its calculation services provided to the user through one or multiple servers
No applications or patch files are required to install on the user’s side, neither any upgrades
The users may perform various types of calculations through PC, iPad or cell phone
The operations can be carried out anytime as long as the devices are connected to the internet
The user accesses to the Service by logging on to the server through username and password. And it is not limited to one particular computer, i.e., the account and password of the user can be shared among the individuals
A “pay as you go" business model is employed and no agreement needs to be signed

Traditional Software

A particular software application or applications and some patch files are required to install on the user’s computer
The requests for upgrades may occur from time to time and the fees for upgrades and maintenance are charged
The calculations are usually performed on PC only, and limited on the PC on which the application(s) are installed
The multiple licenses are usually required among colleagues within the enterprise
The license agreement and the permit to use, must be signed and granted before purchasing

Engineering Software in Cloud (PaaS vs SaaS)

Mon, 01 Jan 2018 08:00:00 GMT

While it is now a trend to develop or transform engineering software applications to Clouding Computing or Cloud Services, it is important to understand the fundamental differences between the two models, Software as a Service (SaaS) and Platform as a Service (PaaS).

PaaS

PaaS distributes traditional software in a cloud environment.
The software applications do not need to be installed or downloaded onto the user’s PC. Instead, the user will be assigned a virtual machine (VM) which is preloaded with the software application that he/she has purchased.
The user logs on the virtual machine to access and run the software through internet.
To the vendor, PaaS saves the tremendous re-development efforts on cloud computing. To the user, it saves the efforts and time on software installation, license configuration, and etc.
A typical workflow of PaaS cloud computing is illustrated as below:
1. The user requests a cloud computing service;
2. The vendor dynamically generates a VM with the requested software pre-loaded on its cloud service cluster, and assigns access permission to the user;
3. The user remotely accesses the VM to run software on the cloud;
4. When the user logs out, the VM is shutdown and the resource is recycled.
PaaS achieves a cloud-based access. However, on the user’s side, his/her experience is still the same as that of traditional software. The difference is that now the software is running on the virtual machine instead of on the user’s computer.
PaaS is a compromised solution when the software re-development or re-coding is very time and cost consuming.

SaaS

The software in the cloud displays in the form of web pages.
No installation of software license or application is required. The user accesses the software through the browser to logon the website. And running software is like riding on a “Hop-On, Hop-Off Bus.”
SaaS is highly compatible and convenient to use. Moreover, SaaS has a powerful potential for secondary development (to build API, application programming interface).
The calculation results can be downloaded, and the data can be easily compared and analysed with that from other software applications. The data sharing can also be achieved with other network platforms, which make it possible to build a big data network.
Currently, the web based software might be less powerful than desktop software. However, with the advancement of web technologies, this gap will be eliminated.
Eventually, SaaS will replace PaaS and other forms of Cloud Computing.

Pros and Cons:

	PaaS	SaaS
Facts	Dedicate a VM for every user License is integrated into the VM	Access service via website Get the licenses when granted access to website
Pros	Less development efforts by using the existing software	Build on a cloud environment Cross platform Easy to access and easy to deploy and upgrade Reduce cost for licensing software Potential for 2^nd development
Cons	Consuming vendor’s resource as every user requires a VM Consuming time on deploying a VM at user’s request for access Consuming network resource on real-time refresh of GUI from server to user, Usually works only on Windows system	Require big efforts for new design and development
Comment	PaaS functions is at a lower level than SaaS and is a compromised solution for large traditional software	In short view, SaaS and PaaS complement each other. Eventually SaaS will replace PaaS

Tank Emission Estimation － Cloud Computing

Wed, 01 Nov 2017 07:00:00 GMT

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Bubble Point and Dew Point

Sun, 01 Oct 2017 07:00:00 GMT

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The Bubble Point is the temperature and pressure at which the first bubble of a vapor appears from a liquid mixture. The Dew Point is the temperature and pressure at which the first “dew” comes out from a gas mixture.

The bubble point temperature may be obtained by heating a liquid at a constant pressure till a first “bubble” come out. It is also the temperature at which the vapor is in equilibrium with the liquid for the given composition. For a pure component, bubble point = boiling point = dew point.

There four (4) types of calculations are provided in this module:

Bubble Point Temperature: to calculate temperature (T) and vapor compositions (y_i) by giving pressure (P) and liquid compositions (x_i)
Bubble Point Pressure: to calculate pressure (P) and vapor compositions (y_i) by giving temperature (T) and liquid compositions (x_i)
Dew Point Temperature: to calculate temperature (T) and liquid compositions (x_i) by giving pressure (P) and vapor compositions (y_i)
Dew Point Pressure: to calculate pressure (P) and liquid compositions (x_i) by giving temperature (T) and vapor compositions (y_i)

There are twelve (12) equations of state available for selection combined with the certain mixing rules：

Soave-Redlich-Kwong (SRK), 1972
Peng-Robinson (PR), 1978
Peng-Robinson (PR), 1976
Peng-Robinson (Magoulas & Tassios revision), 1990
Adachi-Lu-Sugie (ALS), 1983
Patel-Teja, 1982
Valderrama-Patel-Teja, 1990
Schmidt-Wenzel, 1980
Yu-Lu, 1987
Modified Du-Guo, 1989
Trebble-Bishnoi, 1987
Salim Modified Trebble-Bishnoi, 1994

Phase Envelope Diagrams and Isometric Lines (Quality Lines)

Fri, 01 Sep 2017 07:00:00 GMT

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On a P-T diagram of a multicomponent mixture, it shows a temperature and pressure region usually encircled by a curve known as phase envelope. The closed area co-exists two phases. The phase envelope usually consists of a bubble point curve, a dew point curve and a critical point.

In the two-phase region on the P-T diagram, a curve graphing temperature against pressure on which the volume of the mixture remains constant is called isochore or isometric line. For reservoir engineers, the phase envelope and isochore provides essential information to further understand the reservoir fluid properties and make strategic plan on reservoir production.

Technically, the phase envelope may be obtained through a series of bubble point and dew point calculations. It is, however, time consuming and sometime causes a non-converging issue. In this module of the cloud computing, the method established by Michael L. Michelsen (1980) is adopted for the calculations of phase envelope and isometric lines.

There are twelve (12) equations of state available for selection combined with the certain mixing rules：

Soave-Redlich-Kwong (SRK), 1972
Peng-Robinson (PR), 1978
Peng-Robinson (PR), 1976
Peng-Robinson (Magoulas & Tassios revision), 1990
Adachi-Lu-Sugie (ALS), 1983
Patel-Teja, 1982
Valderrama-Patel-Teja, 1990
Schmidt-Wenzel, 1980
Yu-Lu, 1987
Modified Du-Guo, 1989
Trebble-Bishnoi, 1987
Salim Modified Trebble-Bishnoi, 1994

Cricondentherm Hydrocarbon Dew Point

Tue, 01 Aug 2017 07:00:00 GMT

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The hydrocarbon dew point is the temperature at which the first “dew” comes out from a gas mixture for a given pressure. And the highest dew point temperature on a liquid-vapor curve is called cricondentherm hydrocarbon dew point (CHDP) (see the plot).

It is very important for the transportation companies to manage and control the hydrocarbon dew point in the gas transportation through pipelines and production facilities. The necessary measures must be taken to prevent hydrocarbon condensation at the cold conditions. By so doing it not only assures the quality of the gas streams but also prevents pipe corrosion due to the liquids (hydrocarbon and water) forming in the low areas and avoids potential fire and explosion hazards.

The module of cricondentherm hydrocarbon dew point can be integrated into a company’s Supervisory Control and Data Acquisition (SCADA) system to provide the online real-time dew point predictions for multiple sites monitor and control.

As shown in the schematic diagram, a service designed to handle requests from multiple computers in online real-time mode runs as a back process, which receives the data from SCADA through TCP/IP, calls the module to perform the dew point calculations and sends the results back through TCP/IP.

Vapor-Liquid Equilibrium

Sat, 01 Jul 2017 07:00:00 GMT

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The calculation of vapor-liquid equilibrium is also named P-T flash calculation. It performs the calculation of the compositions in both vapor and liquid phases should the system exists vapor and liquid phases.

There are twelve (12) equations of state available for selection combined with the certain mixing rules：

Soave-Redlich-Kwong (SRK), 1972
Peng-Robinson (PR), 1978
Peng-Robinson (PR), 1976
Peng-Robinson (Magoulas & Tassios revision), 1990
Adachi-Lu-Sugie (ALS), 1983
Patel-Teja, 1982
Valderrama-Patel-Teja, 1990
Schmidt-Wenzel, 1980
Yu-Lu, 1987
Modified Du-Guo, 1989
Trebble-Bishnoi, 1987
Salim Modified Trebble-Bishnoi, 1994

If the reservoir fluids contain Cn⁺ (end) fraction, it may be required to perform a characterization on it (please see the calculation module of Characterization of End Fraction in Reservoir Fluids). The calculation results are displayed in term of table and plot.

Vapor-Oil-Water Phase Equilibrium

Thu, 01 Jun 2017 07:00:00 GMT

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The calculation of multiphase equilibrium is also called multiphase P-T flash calculation. This module of cloud computing performs the calculation of multiphase equilibria in the systems containing more than two phases: a gas phase, a liquid hydrocarbon phase, an aqueous phase and solid phase should the system exist multiple phases. At certain conditions, the system exists a CO₂-rich liquid phase. The equilibrium state is characterized by minimizing the Gibbs free energy. The method established by Michael L. Michelsen (1980) is adopted.

The table below shows the prediction results of vapor-liquid 1(HC liquid)-liquid 2(aqueous phase)-liquid 3(CO₂-rich liquid phase) equilibria.

Characterization of End Fraction in Reservoir Fluids

Mon, 01 May 2017 07:00:00 GMT

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The characterization of the end fraction in reservoir fluids plays an important role in predicting the fluids properties and its phase behavior using equations of state. The reservoir fluid samples analyzed by the laboratory consist of an end fraction (C_n⁺) which is a mixture with unknown properties. The characterization on the end fraction is to use a group of pseudo-components to represent it by estimating the physical properties (critical temperature, T_c, critical pressure P_c and acentric factor, ω), so that the cubic equations of state may perform the calculations.

The certain rules have to be followed in the characterization of the end fraction in reservoir fluids including selection of a number of pseudo-components and appropriate correlations for the critical properties. There are three aspects in the fluid characterization:

To determine a distribution function for the reservoir fluid components
To define a number of pseudo-components and group lumping technic
To select the appropriate correlations for the critical properties of the pseudo-component

Please note the results of the characterization for the same fluid sample could be significantly altered by the choice of the distribution functions and the correlations of the critical properties.

In this module, the multiple distribution functions and a group of correlations for critical properties are provided for selection as well as a default setting.

Composition Gradient with Depth in Reservoir

Sat, 01 Apr 2017 07:00:00 GMT

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The temperature and pressure as well as the compositions of the reservoir fluids vary with depth. While the deeper the depth, the higher the temperature and pressure, the compositions of the reservoir fluids are not necessarily changed monotonously. In general, the concentrations of the light components decrease with the depth while that of the heavy components increase. The changes of the compositions cause the changes of the fluid properties, such as, density and viscosity, etc. It is, therefore, very important to understand the composition gradient with the depth in reservoir in order to assess the reservoir and to make strategic plan in exploration and production.

There are many factors that lead to the variation of the reservoir fluid compositions, for example, biodegradation, and mass transfer caused by the convection of the reservoir fluids. In this module of cloud computing, the equations of state are applied for the calculations of fluid compositions and properties changed with the depth in reservoir that are driven by fluid gravity, heat diffusivity and chemical potential.

The results of the calculations are displayed in terms of tables and 3-D phase diagram. The attached plot shows the phase behavior changed at the depth of 2,500 meter to 2,520 meter for a given reservoir fluid.

Contamination Analysis of Reservoir Fluids by OBM

Wed, 01 Mar 2017 08:00:00 GMT

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The oil-based muds (OBM) are commonly used in the drilling process of crude oil due to its resistance to high temperature and corrosion, good lubrication and least to formation damage. However, the samples taken from the underground after the well completion are often contaminated by the OBM which fail to represent the compositions and properties of the original reservoir fluids. It is, therefore, necessary to determine the contamination degree of the samples and to correct the PVT properties that are measured based on the contaminated samples, such as, saturation pressure, GOR, viscosity, density and formation volume factor, etc. In general, the compositions of the “clean samples” appear to follow a certain distribution pattern which can be used to determine the contamination of the fluid samples.

There are two methods to determine the contamination for a given sample: the Subtracting Method where the composition of the OBM is known; and the Skimming Method where the composition of the OBM is unknown.

Once the contamination is determined, i.e., the compositions of the “clean sample” are obtained, the correction of the PVT properties can be done following the procedures below:

Performing the characterization using a couple of pseudo-components to represent the OBM (see Characterization of End Fraction in Reservoir Fluids);
Creating a “new oil sample” to include the pseudo-components;
Tuning the EOS model to match the measured the PVT properties based on the contaminated sample;
Predicting the PVT properties of the “clean oil sample” (setting compositions of the pseudo-components to zero) and comparing them to that of the contaminated oil sample.

PVT Properties

Wed, 01 Feb 2017 08:00:00 GMT

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Currently, four common PVT properties are provided:

Gas FVF
Oil FVF
GOR
Gas Recovery

The future development includes the following calculations of the PVT properties of oil, gas and formation water using the equations of state and the correlations.

Oil

Oil Formation volume factor, FVF（B_o）
Bubble point
GOR
Viscosity of live oil (saturated)
Viscosity of live oil (unsaturated)
Viscosity of dead oil
Live oil compressibility (saturated, P<P_b)
Live oil compressibility (unsaturated, P>P_b)

Gas

Critical Properties (known gas compositions)
Critical Properties (known gas gravity)
Z Factor
Gas viscosity
Gas Compressibility

Formation water

Water formation volume factor, FVF（B_o）
Solution gas-water ratio
Viscosity
Compressibility (saturated, P<P_b)
Compressibility (unsaturated, P>P_b)

PVT Tests Simulation (CCE, DL, CVD, Separator)

Wed, 01 Feb 2017 08:00:00 GMT

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CCE (Constant Composition Expansion / Constant Mass Expansion) Test

To optimize the exploration and production from oil and gas fields, the reservoir fluid samples are taken and sent to the laboratory for a series of tests to gain the knowledge of producing best quality products in a most economical way under the changes of pressure and temperature of the reservoir. For example, it is essential to understand at what conditions the initial one-phase fluid splits into two phases and the compositions and the properties of each phase, etc. Such tests are called PVT tests and the properties PVT properties which usually are expressed as functions of pressure and temperature.

Once the compositions are determined at the laboratory, the CCE test is usually the first undergo test for either conventional oil or gas condensates. The test starts from the pressure higher than bubble point pressure at the reservoir temperature, and gradually decreases the pressure (hence the volume being expended at constant composition). The bubble point or dew point and the fluid properties changed with pressure and temperature are obtained from the test (see the schematic diagram).

This module of cloud computing is the process simulation of the CCE teat by the laboratory and can also be used to make a plan for a test workflow and an estimate of the test results.

DL (Differential Liberation) Test

The DL test starts from the bubble point pressure (for conventional oil) or dew point pressure (for gas condensate), and gradually decreases the pressure at a constant temperature. The volumes of the oil and the gas at each step are measured and the depleted gas is collected. Like CCE test, the purpose of the DL test is to understand the phase behavior and the PVT properties of the reservoir fluid at the reservoir conditions. It is also to obtain the information of the oil volume at the reservoir conditions as compared to that at the standard conditions, i.e., the oil formation volume factor, B_o and the gas formation volume factor, B_g.

CVD (Constant Volume Depletion) Test

The CVD test starts at the dew point pressure of the gas condensate, and measures the saturation volume at the dew point, V_sat. As the pressure decreases, the volume increases to form the gas-oil two phases. The gas is depleted from a valve at the top of the cylinder to keep the total volume of the two phases equal to the saturation volume at a constant pressure (see the schematic diagram). The percentage of the depleted gas as to the original gas is measured as well as the percentage of the liquid dropout of the liquid volume as to the saturation volume.

The PVT properties of the gas condensate or the volatile oil as they may change with each stage in the productions are obtained.

Separator Test

The objective of the separator test is to optimize the amount of oil produced at the surface. The test is carried out for either oil and gas condensate in single or multiple separators with the last stage at atmospheric pressure and temperature.

A sample of reservoir fluid is placed in the laboratory cell and brought to reservoir temperature and bubble point pressure. Then the oil is expelled from the cell to the next separator stage while the gas is let out and transferred to standard conditions. The process is repeated until stock tank conditions are reached. The solution GOR and the oil formation volume factor, Bo are measured in the test.

Formation of Gas Hydrate

Sun, 01 Jan 2017 08:00:00 GMT

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The gas hydrate is an “ice-like” crystal and formed by certain gas molecules trapped inside of "cages" of water molecules through hydrogen bonds. It is usually formed at high pressure and low temperature, but can also be formed at an ambience temperature.

Once it forms, the clathrate hydrates may quickly grow and block the pipelines and/or the production facilities, and result in the cease of production and even in the explosion. It is, therefore, a serious issue that the industry needs to pay attention in the oil field production and the process design and development.

Beside to keep the production facility and the pipeline working at the high temperature and low pressure conditions, the industry uses hydrate inhibitors to prevent hydrate from forming. There are two types of hydrate inhibitors: thermodynamic inhibitors and kinetic inhibitors. The application of the former ones is to drop the hydrate formation temperature at a given pressure; and that of the latter one is to delay the hydrate forming time.

Formation water contains some salts, such as, NaCl, KCl and CaCl₂ which are actually hydrate inhibitors and can be used together with some organic inhibitors to effectively drop the hydrate formation temperature at a given pressure.

This module of cloud computing performs the accurate and reliable predictions of hydrate formation conditions in the absence / presence of hydrate inhibitor or inhibitors (the hydrate formation curve); the maximum water contents before the hydrate could form; and the minimum injection of hydrate inhibitor to prevent hydrate from forming.

Lumping and De-lumping of Reservoir Fluids

Wed, 06 Jan 2016 18:10:00 GMT

Lumping and De-lumping of Reservoir Fluids

The reservoir fluid usually consists of dozens, even hundreds of components. To perform the fluid property and phase equilibrium calculations for such a large group of mixture is quite time consuming and unpractical, especially to feed them as input to a reservoir simulator to perform simulations. It is, therefore, desirable to reduce that number into a few pseudo-components (usually less than 10) to accurately represent the original mixture. The process requires “lumping” technics in which the critical properties (T_c, P_c and ω) of the individual carbon number fractions are averaged to one set of the critical properties for the lumped pseudo-component or group.

On the other hand, when performing downstream process simulation, it is required to have the detailed fluid compositions which are heavily lumped in the process of reservoir simulation. Also, the reservoir fluid samples taken and analyzed in-situ often consist of only a few components that require “de-lumping” technics to revert to reservoir fluid as much as possible.

Lumping and de-lumping technics that couple the calculations in upstream and downstream processes are involved in a serial of the thermodynamic steps.