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Reservoir Simulation Data Management

Reservoir Simulation Data Management

Eng.Ali Yahya Jirjees Salman


Introduction
Data from a wide variety of sources are required for reservoir simulation. Simulation itself produces large quantities of data. Yet, good data management practices for reservoir simulation data are typically neither well-understood nor widely investigated.
Reservoir simulation is inherently a data-intensive process. It starts with geological models and their properties, and assignment of phase behavior or equation of state data, relative permeability and capillary pressure information and geo-mechanical data. It requires layout of the surface facility network, subsurface configuration of wells, their attributes, pressure and rate limits and other production and optimization constraints. Very often, production history information, hydraulics tables, completion tables and logic for runtime management of wells and surface facilities are needed. Finally, special cases like thermal and fractured reservoir simulations require their own set of additional data.

During simulation, time-stepping information, convergence parameters and well performance data can be logged and analyzed. Results, such as pressures and rates from wells and surface facilities and pressures and saturations from the simulation grid can be monitored and recorded. The state of the simulator can be recorded at specified intervals to enable restart of a run at a later time.

This result in an abundance of data to be analyzed, visualized, summarized, reported and archived. Over the years, many authors have tried to address one aspect or another of this data management problem and many commercial and proprietary simulators have made allowances to simplify users’ work in this area. However, in general, data management has not been a widely investigated aspect of reservoir simulation.

Data management in reservoir simulation enables workflows and collaboration, insures data integrity, security and consistency and expedites access to results. In today’s computing environment, data management is an enabler to meet the growing need for reservoir simulation and to make simulation available to a wider audience of professionals, including many kinds of engineers and geoscientists.

Reservoir Management

The main goal of oil reservoir management is to provide more efficient, cost-effective and environmentally safer production of oil from reservoirs. Implementing effective oil and gas production requires optimized placement of wells in a reservoir. A production management environment involves accurate characterization of the reservoir and management strategies that involve interactions between data, reservoir models, and human evaluation. In this setting, a good understanding and monitoring of changing fluid and rock properties in the reservoir is necessary for the effective design and evaluation of management strategies. Despite technological advances, however, operators still have at best a partial knowledge of critical parameters, such as rock permeability, which govern production rates; as a result, a key problem in production management environments is incorporating geologic uncertainty while maintaining operational flexibility.

Combining numerical reservoir models with geological measurements (obtained from either seismic simulations or sensors embedded in reservoirs that dynamically monitor changes in fluid and rock properties) can aid in the design and implementation of optimal production strategies. In that case, the optimization process involves several steps:

1. Simulate production via reservoir modeling;
2. Detect and track changes in reservoir properties by acquiring seismic data (through field measurements or seismic data simulations);
3. Revise the reservoir model by imaging and inversion of output from seismic data simulations.

Reservoir Simulation

As stated earlier, one challenging problem in the overall process is incorporating geological uncertainty. An approach to address this issue is to simulate alternative production strategies (number, type, timing and location of wells) applied to multiple realizations of multiple geo-statistical models. In a typical study, a scientist runs an ensemble of simulations to study the effects of varying oil reservoir properties (e.g. permeability, oil/water ratio, etc.) over a long period of time. This approach is highly data-driven. Choosing the next set of simulations to be performed requires analysis of data from earlier simulations.

Another major problem is the enormity of data volumes to be handled. Large-scale, complex models (several hundreds of thousands of unknowns) often involve multiphase, multicomponent flow, and require the use of distributed and parallel machines. With the help of large PC clusters and high performance parallel computers, even for relatively coarse descriptions of reservoirs, performing series of simulations can lead to very large volumes of output data. Similarly, seismic simulations can generate large amounts of data. For example, downhole geophysical sensors in the field and ocean bottom seismic measurements are episodic to track fluid changes. However, per episode, these involve a large number (e.g. hundreds to thousands) of detectors and large numbers of controlled sources of energy to excite the medium generating waves that probe the reservoir.

These data are collected at various time intervals. Thus, seismic simulators that model typical three-dimensional seismic field data can generate simulation output that is terabytes in size. As a result, traditional simulation approaches are overwhelmed by the vast volumes of data that need to be queried and analyzed.

We can state now a definition of reservoir management process which is the utilization of the available resources (i.e., human, technological and financial)) in order to:
1. Maximize benefits (profits) from a reservoir by optimizing recovery.
2. Minimizing capital investments and operating expenses.

Objectives of Reservoir Management

Data replication is common across reservoir simulation models. Initially, a few base reservoir simulation models were available for a reservoir, e.g., P10, P50, and P90 models. These models are used extensively used to explore and evaluate different field development plans or field management strategies. As a result of exploration or evaluation, many more models are derived from these base reservoir models. A derived reservoir model is usually created in two steps:

1. Copying a base reservoir model.
2. Modifying parameter values in the copy.

Furthermore, the derived models can also be used to derive new models. Data replication poses many challenges to reservoir simulation model management. The first challenge is the efficiency of management. Data replication results in new relationships among models. The new relationships can be created based on data components shared by various models. Managing these relationships results in overhead. For example, additional metadata used to track the relationships must be captured and stored. The second challenge caused by data replication is maintaining data consistency among various reservoir simulation models.

Generally, the more one replicates, the more points of divergence are created and the more one is subject to incorrect behaviors. On the other hand, base reservoir simulation models are regularly updated or calibrated as historical production data of the reservoir become available (the process is called history matching in petroleum engineering). Due to the complexity of a reservoir simulation model, propagating changes in these base models properly and efficiently is nontrivial.

So we can summarize the objectives for managing the reservoir in the following points:

– Decrease risk.
– Increase oil and gas production.
– Increase oil and gas reserves.
– Minimize capital expenditures.
– Minimize operating costs.
– Maximize recovery.
– Identify and define all individual reservoirs in a particular field and their physical properties.
– Deduce past and predict future reservoir performance.
– Minimize drilling of unnecessary wells.
– Define and modify (if necessary) wellbore and surface systems.
– Initiate operating controls at the proper time.
– Consider all pertinent economic and legal factors.

Why and when should reservoir management be used?

The ideal time to start managing a reservoir is at its discovery, because:

  1. Early initiation provides a better monitoring and evaluation tool,
  2. Costs less in the long run.

A good example of that can be an extra log or an additional hour’s time on a DST may provide better information than could be obtained from more expensive core analysis. It is possible to do some early tests that can indicate the size of a reservoir. If it is of limited size, drilling of unnecessary wells can be prevented.

The magnitude of the investments associated with developing oil and gas assets motivates the consideration of methods and techniques that can minimize these outlays and improve the overall economic value. For several decades, industry practices have attempted to address this issue by considering a variety of approaches that can be referred to collectively as traditional methods. These methods include trial-and-error approaches that conduct a series of “what if” analyses or case studies as well as heuristic and intuition-based efforts that impose rules and learning on the basis of experience or analogies. In contrast, mathematical-optimization techniques can provide an efficient methodology toward achieving these goals by combining all the traditional approaches into a comprehensive and systematic process.

We can overview a case history that shows the effect on production targets between the use of reservoir management and without it.

The case includes the development of a regional complex of gas reservoirs similar to those found in the Gulf of Mexico, the southern gas basin of the North Sea, West Africa, and in basins in the Far East is examined. The example in this paper is an amalgamation of the fields typically developed around the world.

The complex to be developed consists of three main fields with at least one additional satellite. It is assumed that several development decisions have already been made when this work commences. For example, the gas in place for each reservoir; the size, configuration, and number of platforms; and the pipeline infrastructure have been determined or specified. The layout of the reservoirs and infrastructure is shown below.Reservoir Simulation

The Reservoir A platform has eight well slots, with each well costing U.S. $15 million. Sand production and water coning place flow limitations on the different wells, ranging from 10 to 25 MMscf/D. Water influxes occurs in Reservoir A, although the relatively high production rates limit the support to approximately 100 psi for the period of interest. Flow limitations for wells in Reservoirs B and C are comparable to wells in Reservoir A, although Reservoir B does contain one well that can produce up to 30 MMscf/D. The total gas handling capacity at the terminal is 200 MMscf/D, and the gas must be delivered at a pressure of at least 900 psi.And here is a schematic graphs show the great difference in producing the different cases with the use of reservoir management and without.

Reservoir SimulationA brief description of the cases considered is provided in the following table, and the economic results of these cases are summarized in the following Figure. This figure shows the cases without mathematical optimization in the upper left portion. Capital efficiency is improved by simultaneously lowering capital costs while increasing production, as demonstrated by the optimized cases in the lower right portion of the graph. The comparison demonstrates the advantage of an optimization-based approach to reservoir management that completely integrates the workflow to make decisions that drive capital investment, scheduling, production, recovery, and, ultimately, asset performance.

The highly nonlinear nature of the physical system and the combinatorial complexity of development decisions warrant the proper modeling of the assets, the appropriate formulation of the optimization systems, and the use of tailored state-of-the-art mathematical techniques to render these numerical systems tractable. However, the considerable economic benefits, as demonstrated in this paper, provide the motivation for use of these techniques. Because most of the capital-investment commitments are made in the early life of an asset, a narrow window of opportunity exists to influence the economic performance of the asset. Thus, there is a clear need to apply such technology at the earliest opportunity.

Reservoir Simulation

Reservoir Management Team Involved

Reservoir management process should be through a team approach in order to:

– Facilitate communication among various engineering disciplines, geology, and operations.
– The engineer must develop the geologist’s knowledge of rock characteristics and depositional environment, and a geologist must cultivate knowledge in well completion and other engineering tasks, as they relate to the project at hand.
– Each member should subordinate their ambitions and egos to the goals of the reservoir management team.
– Each team member must maintain a high level of technical competence.
– Reservoir engineers should not wait on geologists to complete their work and then start the reservoir engineering work. Rather, a constant interaction between the functional groups should take place.

The reservoir management team should include the following elements at any company:

1.  Management.
2. Geology and geophysics.
3. Reservoir engineering.
4. Economics and finance.
5. Drilling engineering.
6. Design and construction engineering.
7. Production and operation engineering.
8. Gas and chemical engineering.
9. Research and development.
10. Environment.
11. Legal and landlords.
11. Services provider.

Reservoir Management Process

The process of managing the reservoir includes:

  • Setting strategy (goals): The key elements for setting the reservoir management goals are:
  1. Reservoir characteristics.
  2. Total environment.
  3. Available data.
  • Developing a plan:
  1. Development and depletion strategy
  2. Environmental consideration.
  3. Data acquisition and analysis.
  1. Geological & numerical model studies
  2. Production and reserve forecast.
  3. Facilities requirement.
  4. Economic optimization.
  1. Management approval.
  • Implementation:
  1. Start with a plan of action, involving all functions.
  2. Flexible plan.
  3. Management support.
  4. Commitment of field personal.
  1. Periodic review meeting, involving all team members.
  • Monitoring.
  • Evaluation.
  • Completing.

 

  • Reasons of Failure Of Reservoir Management:
  1. Un-integrated system.
  2. Starting too late.
  1. Lack of maintenance.
  2. Having multiple bosses.
    5. Data non-continuity & unreliability.

Data Management

Throughout the life of a reservoir, from exploration to abandonment, an enormous amount of data are collected. An efficient data management program consisting of acquisition, analysis, validating, storing, and retrieving plays a key role in reservoir management.

List of data types in reservoir simulation process:Reservoir Simulation TypesReservoir Simulation TypesManagement of reservoir simulation models includes two tasks. One is the management of models’ data files. In a file-based approach, the management mainly concerns the directory hierarchy for storing the models, including naming of the data files and directories. The second task is the management of relationships between the models, such as data sharing.
Two models are considered to have a data sharing relationship if they share a portion of their model data. For example, two models might share the same historical production data and well completion data. Data sharing relationships are very common among reservoir simulation models. However, data sharing among simulation models results in data replicas. The complete data of a model are typically stored in a repository managed by traditional approaches. If part of a model is shared by multiple models, multiple replicas of the data are created and distributed in each of those models.

These data replicas cause two problems to the repository. The first is concerned with the storage efficiency. The second is related to data consistency among the models with shared data components. In an oilfield asset, reservoir simulation models are regularly updated or calibrated as historical production data of the reservoir become available (the process is called history matching in petroleum engineering). Due to the complexity of a reservoir simulation model, propagating changes in these models properly and efficiently is a nontrivial task. Therefore, reducing data replicas in the repository is desirable in the management of reservoir simulation models.
Data replication has been studied extensively in the area of distributed systems. Previous research efforts can be classified into two categories. The first category focuses on data replication across a distributed system to improve reliability, fault-tolerance, or accessibility of the system. The second category addresses data consistency resulting from data replication. Replica consistency techniques and systems have been developed for this purpose. However, to the best of our knowledge, no existing work has addressed the data replica problem in the management of simulation models.

 Reasons of Failure

  1. Un-integrated systems.
  1. Starting too late.
  2. Lack of maintenance.
  3. Having multiple bosses.
  4. Data non-continuity and unreliability.

 

    References

  • Integrated Petroleum Reservoir Management Abdus Satter, Ph.D. ,Research Consultant , Texaco E&P Technology Department , Houston, Texas / Ganesh C. Thakur, Ph.D. , Manager-Reservoir Simulation Division , Chevron Petroleum Technology Company , La Habra, California.
  • Applying Optimization Technology in Reservoir Management

               Vasantharajan, Optimal Decisions Inc.; R. Al-Hussainy, Amerada Hess Ltd.; and R.F. Heinemann, Berry
Petroleum Co.

  • A simulation and data analysis system for large-scale, data-driven oil reservoir simulation studies, Pract. Exper. 2005; 17:1441–1467, Tahsin Kurc1,†, Umit Catalyurek1, Xi Zhang1, Joel Saltz1, Ryan Martino2, Mary Wheeler2, Małgorzata Peszy´nska3.

Geologic Classification of Petroleum Reservoirs

 

Petroleum reservoirs exist in many different sizes and shapes of geologic structures. It is usually convenient to classify the reservoirs according to the conditions of their formation as follows:

A reservoir formed by folding of rock layers.
Figure 1

1. Dome-Shaped and Anticline Reservoirs:

These reservoirs are formed by the folding of the rock layers as shown in Figure 1. The dome is circular in outline, and the anticline is long and narrow. Oil and/or gas moved or migrated upward through the porous strata where it was trapped by the sealing cap rock and the shape of the structure.

 

2. Faulted Reservoirs:

A cross section of a faulted reservoir.
Figure 2

These reservoirs are formed by shearing and offsetting of the strata (faulting), as shown in Figure 2. The movement of the nonporous rock opposite the porous formation containing the oil/gas creates the sealing. The tilt of the petroleum-bearing rock and the faulting trap the oil/gas in the reservoir.

 

 

3. Salt-Dome Reservoirs:

Section in a salt-dome structure
figure 3

This type of reservoir structure, which
takes the shape of a dome, was formed due to the upward
movement of large, impermeable salt dome that deformed and
lifted the overlying layers of rock. As shown in Figure 3,
petroleum is trapped between the cap rock and an underlying
impermeable rock layer, or between two impermeable layers of
rock and the salt dome.

 

 

4. Unconformities:

A reservoir formed by unconformity.
figure 4

This type of reservoir structure, shown in Figure 4, was formed as a result of an unconformity where the
impermeable cap rock was laid down across the cutoff surfaces of the lower beds.

 

 

 

5. Lense-Type Reservoirs:

In this type of reservoir, the petroleum bearing porous formation is sealed by the surrounding, nonporous formation. Irregular deposition of sediments and shale at the time the formation was laid down is the probable cause for this abrupt change in formation porosity.

6. Combination Reservoirs:

In this case, combinations of folding, faulting, abrupt changes in porosity, or other conditions that create the trap, from this common type of reservoir.

Reservoir Drive Mechanisms
At the time oil was forming and accumulating in the reservoir, the pressure energy of the associated gas and water was also stored. When a well is drilled through the reservoir and the pressure in the well is made to be lower than the pressure in the oil formation, it is that energy of the gas, or the water, or both that would displace the oil from the formation into the well and lift it up to the surface. Therefore, another way of classifying petroleum reservoirs,
which is of interest to reservoir and production engineers, is to characterize the reservoir according to the production (drive) mechanism responsible for displacing the oil from the formation into the wellbore and up to the surface. There are three main drive mechanisms:

I. Solution-Gas-Drive Reservoirs:
Depending on the reservoir pressure and temperature, the oil in the reservoir would have varying amounts of gas dissolved within the oil (solution gas).
Solution gas would evolve out of the oil only if the pressure is lowered below a certain value, known as the bubble point pressure, which is a property of the oil. When a well is drilled through the reservoir and the pressure conditions are controlled to create a pressure that is lower than the bubble point pressure, the liberated gas expands and drives the oil out of the formation and assists in lifting it to the surface.
Reservoirs with the energy of the escaping and expanding dissolved gas as the only source of energy are called solution-gas-drive reservoirs.
This drive mechanism is the least effective of all drive mechanisms; it generally yields recoveries between 15% and
25% of the oil in the reservoir.

II. Gas-Cap-Drive Reservoirs:
Many reservoirs have free gas existing as a gas cap above the oil. The formation of this gas cap was due to the presence of a larger amount of gas than could be dissolved in the oil at the pressure and temperature of the reservoir. The excess gas is segregated by gravity to occupy the top portion of the reservoir.
In such a reservoirs, the oil is produced by the expansion of the gas in the gas cap, which pushes the oil downward and fills the pore spaces formerly occupied by the produced oil. In most cases, however, solution gas is also
contributing to the drive of the oil out of the formation.
Under favorable conditions, some of the solution gas may move upward into the gas cap and, thus, enlarge the gas cap and conserves its energy. Reservoirs produced by the expansion of the gas cap are known as Gas-cap-drive
reservoirs. This drive is more efficient than the solution-gas drive and could yield recoveries between 25% and 50% of the original oil in the reservoir.

III. Water-Drive Reservoirs:
Many other reservoirs exist as huge, continuous, porous formations with the oil/gas occupying only a small portion of the formation. In such cases, the vast formation below the oil/gas is saturated with salt water at very high pressure. When oil/gas is produced, by lowering the pressure in the well opposite the petroleum formation, the salt
water expands and moves upward, pushing the oil/gas out of the formation and occupying the pore spaces vacated by the produced oil/gas. The movement of the water to displace the oil/gas retards the decline in oil, or gas pressure, and conserves the expansive energy of the hydrocarbons.
Reservoirs produced by the expansion and movement of the salt water below the oil/gas are known as water-drive
reservoirs. This is the most efficient drive mechanism; it could yield recoveries up to 50% of the original oil.

References:
Petroleum and Natural Gas Field Processing
 -H. K. Abdel-Aal and Mohamed Aggour

Petroleum Reservoirs Books 2

Applied Reservoir Engineering, Smith, Part.1    Download

Applied Reservoir Engineering, Smith, Part.2   Download


Applied Petroleum Reservoir Engineering – Craft
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  Basic Applied Reservoir Simulation
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the Practice of Reservoir Engineering
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   Essentials of Reservoir Engineering, Donnez
Download


Reservoir Material Balance
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Reservoir Engineering Tarek Ahmed
Download


A Reservoir Simulator for Studying Productivity
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  Fundamentals of Fractured Reservoir Engineering
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  How to Characterize Fractured Reservoirs
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  Handbook of Porous Media
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The Reservoir Engineering Aspects Of Fractured Formations
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Principles of Sedimentology and Stratigraphy
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production operation vol 1 (well completions, workover, and stimulation)   Download 

production operation vol 2 (well completions, workover, and stimulation)  Download


  Sandstone Reservoirs
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Determination of Absolute and Relative Permeability
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Basics of Reservoir Simulation
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Porosity, Permeability & Skin Factor
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Determination of Oil and Gas Reserves
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Reservoir Fluids
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Hydraulic Fracturing Stimulation Techniques and Formation Damage
Download


Properties of Petroleum Reservoir Fluids
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Low Permeability Gas Reservoirs
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Water Flooding
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Origin and Prediction of Abnormal Formation Pressure
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Formation Pressure
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Hydraulic Fracturing Explained – Evaluation, Implementation, and Challenges
Download


Advanced Petroleum Reservoir Simulation
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Hydrocarbon Traps
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Reservoir Formation Damage
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Advances in Reservoir Geology
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Reservoir Characterization – Mohammed AlHossainy
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Sandstone Petroleum Reservoirs
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Sandstone Reservoirs
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Abnormal Formation Pressure
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Reservoir Model Design, A Practitioner’s Guide
Download


Core Well Logging
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Understanding Petroleum Reservoirs
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Unconventional Gas Reservoirs Evaluation, Appraisal and Development
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Location of Fluids in Oil and Gas Reservoirs
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Exploring for Stratigraphic Traps
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Characterization of Naturally Fractured Reservoirs
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Formation Evaluation using Routine Core Analysis
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Reservoir
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World Atlas of Oil and Gas Basins
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Volcanic Reservoirs in Petroleum Exploration
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Hydraulic Fracturing Explained – Evaluation, Implementation, and Challenges
Download


The Petroleum System From Source to Trap
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Fractured Reservoirs
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Origin and Predection of Abnormal Formation Pressures
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Advanced Formation Evaluation
Download Link 1      Download Link 2


Marine Petroleum Source Rocks
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Introduction to Wettability of Oil Reservoir
Download


Permeability Estimation
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Formation Pressure
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Complex Lithology Evaluation
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Understanding Tight Oil
Download


Stratigraphic Reservoir Characterization for Petroleum Geologists, Geophysicists, and Engineers

1st Edition    Download
2nd Edition  Download


a boundary integral method applied to water coning in oil reservoirs
Download Link 1      Download Link 2


Density and Porosity of Oil Reservoirs and Overlaying Formations
Download Link 1     Download Link 2


Reservoir Quality Prediction in Sandstones and Carbonates
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Petroleum Reservoir Rock and Fluid Properties
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Quantitative Methods in Reservoir Engineering
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Experimental Design in Petroleum Reservoir Studies
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Production Enhancement with Acid Stimulation
Download Link 1       Download Link 2


Basin to Basin – Plate Tectonics in Exploration from Schlumberger
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Role of Clay in Oil Reservoirs
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Solution Gas Drive in Heavy Oil Reservoirs
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Sedimentary Basins & Petroleum Geology
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Petroleum Traps Supplementary Notes
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Seismic Stratigraphy, Basin Analysis and Reservoir Characterization
Download


Production Strategy for Thin-Oil Columns in Saturated Reservoirs
Download Link 1      Download Link 2


Exploration for Sandstone Stratigraphic Traps
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Reviving Abandoned Reservoirs with High Pressure Air Injection
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major Oil Reservoir in Permian Basin
Download Link 1           Download Link 2


Fundamentals of Basin and Petroleum Systems Modeling
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Geomorphology of Oil and Gas Fields in Sandstone Bodies
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Hydrogeodynamics of Oil and Gas Basins
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Mass Properties of Sedimentary Rocks and Gravimetric Effects of Petroleum and Natural Gas Reservoirs
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Isolation of Biosurfactant Producing Bacteria from Oil Reservoirs
Download Link 1      Download Link 2


Wettability at High Temperatures 
Download Link 1      Download Link 2


Wettability  
Download Link 1      Download Link 2

Reservoir Simulation Software Movies

in this section you will find a lot of videos about Reservoir Simulation software such as: Petrel – Eclipse – CMG – OFM and many others, all you have to do is to choose the required video and then click on Download link to be redirected to the download page directly.

Building Flow Simulation Models
Download Link 1     Download Link 2


 Demonstration of Reservoir Modeling
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 dynamic model (petrel & eclipse)  Arabic
Download Link 1     Download Link 2


 Dynamic Modeling Throughout the Life of a Well
Download Link 1     Download Link 2


 Eclipse
Download Link 1     Download Link 2


  Reservoir Modeling
Download Link 1     Download Link 2


 ECLIPSE Chemical EOR Presentation
Download Link 1     Download Link 2


 Flow simulation how its done on petrel (Reservoir Engineer)
Download Link 1     Download Link 2


 From Seismic to Simulation Geologic Integrity, 3D Reservoir Models
Download Link 1     Download Link 2


 How to import and View CSEM data in Petrel
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 Improvements to the Petrosys Plugin for Petrel
Download Link 1     Download Link 2


 INTERSECT simulator–New insight with high resolution reservoir simulation
Download Link 1     Download Link 2


  Well modeling Steady-state to dynamic
Download Link 1     Download Link 2


 OFM Monitoring and Surveillance Workflows
Download Link 1     Download Link 2


 Optical Stacking plugin for Petrel
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 perforation input by petrel
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 Petrel
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Petrel 2014 Building Complex Models in Extensional & Compressional Settings
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 Petrel 2014 EAGE Presentation
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 Petrel Interface part 1     Download 

 Petrel Interface part 2     Download Link 1     Download Link 2


 petrel model (Notes)
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 petrel model
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 Petrel
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 Petrosys Data Transfer With Petrel
Download Link 1     Download Link 2


 Reservoir 3D Model by Petrel Software
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 Reservoir Engineering Overview
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 Roxar’s Tempest Reservoir Simulator
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  Simulation with Petrel
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  CMG Tutorial #1
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  CMG Tutorial #2
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  CMG Tutorial #3
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  CMG Tutorial #4
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  CMG Field Development
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 Visualizations for Simulation Results in Eclipse
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Eclipse Tutorial Part.1  
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Eclipse Tutorial Part.2  
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Eclipse Tutorial Part.3  
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 Seismic Inversion in Reservoir Modeling – Part 1
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 Seismic Inversion in Reservoir Modeling – Part 2
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 Seismic Inversion in Reservoir Modeling – Part 3
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Seismic Inversion in Reservoir Modeling – Part 4
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Seismic Inversion in Reservoir Modeling – Part 5
Download


tNavigator Advanced Examples Part.2

 Download 


tNavigator Advanced Examples Part.3   

 Download 


tNavigator Advanced Examples Part.4

 Download 


Slb Eclipse software two wells model run

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Static Model of Petrel SoftwareDownload

Reservoir Engineering Movies

this page contains a lot of movies about petroleum reservoirs, reservoir engineering, reservoir models, reservoir performance and water drive.

 A 3D Geological Model, So What?
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  Applied Petroleum Reservoir Engineering
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  From Seismic to Simulation Geologic Integrity, No Compromise on 3D Reservoir Models
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  Gas Cap Drive Empje por Capa de Gas
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  MBE (Material Balance Equation)
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  How 3D Seismic Is Used To Explore Oil And Gas Geophysics Rocks
Download


  Petroleum Exploration Part 1      Download

  Petroleum Exploration Part 2      Download

  Petroleum Exploration Part 3      Download

  Petroleum Exploration Part 5     Download

  Petroleum Exploration Part 6      Download

  Petroleum Exploration Part 7      Download

  Petroleum Exploration Part 8     Download


  Reservoir Performance Part 1     Download

  Reservoir Performance Part 2     Download


 Reservoir – Solution Gas Drive
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 an introduction 3D Seismic Geophysics Rocks
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  Water Drive
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  What is Stochastic Reservoir Simulation
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Natural Gas Industry

Natural Gas Terminology:

Reservoir: Porous & permeable underground formation containing an individual bank of H.C.s confined by impermeable rock or water barriers characterized by a single natural pressure system.

read also What is Natural Gas

Field: Area of one or more reservoirs related to same structural feature.

Pool: Contains one or more reservoirs in isolated structures.

Wells can be classified as gas wells, condensate wells, and oil wells.

Gas wells: Wells with producing gas-oil ration (GOR)>100,000 scf/stb.

Condensate wells: Producing GOR < 100,000 scf/stb but > 5,000 scf/stb.

Oil wells: Wells with producing GOR < 5,000 scf/stb

Because NG is petroleum in a gaseous state, it is always accompanied by oil that is liquid petroleum. There are 3 types of NG: nonassociated gas, associated gas & gas condensate.

Nonassociated gas: Gas from reservoirs with minimal oil.

Associated gas: Gas dissolved in oil under natural conditions in the oil reservoir.

Gas condensate: Gas with high content of liquid H.C. at reduced P & T.

Utilization of Natural Gas

–  Natural gas is one of the major fossil energy sources.

– Combustion of 1 scf of NG generates 700 → 1,600 Btu of heat, depending upon gas composition.

– NG provided close to 24% of U.S. energy sources over 2000-2002.

– NG is used as a source of energy in all sectors of the economy.

– Natural gas was once a by-product of crude oil production.

– Since its discovery in 1821 in U.S.A. in Fredonia, New York, NG has been used as fuel in areas immediately surrounding the gas fields.

– In the early years of NG industry, when gas accompanied crude oil, it had to find a market or be flared; in the absence of effective conservation practices, oil-well gas was often flared
in huge quantities.

Consequently, gas production at that time was often short-lived, and gas could be purchased as low as 1 or 2% per 1,000 ft3 in the field.

– Consumption of NG in all end-use classifications (residential , industrial, commercial & power generation) increased rapidly since World War II.

– This growth resulted from several factors, including:

– Development of new markets.

– Replacement of coal as fuel for providing space & industrial process heat.

– Use of NG in making petrochemicals and fertilizers.

– Strong demand for low-sulfur fuels.

– The rapidly growing energy demands of Western Europe, Japan & U.S.A. couldn’t be satisfied without importing gas from far fields.

– Natural gas, liquefied by a refrigeration cycle, can now be transported efficiently and rapidly across the oceans by insulated tankers.

– The use of refrigeration to liquefy NG, and hence reduce its volume to the point where it becomes economically attractive to transport across oceans by tanker.

– It was first attempted on a small scale in Hungary in 1934 and later used in U.S.A. for moving gas in liquid form Louisiana up the Mississippi River to Chicago in 1951.

– The first use of a similar process on a large scale outside U.S.A. was the liquefaction by a refrigerative cycle of some of the gas from the Hassi R’Mel gas field in Algeria and the export
from 1964 onward of the resultant liquefied natural gas (LNG) by specially designed insulated tankers to Britain & France.

– NG is in this way reduced to about 1/600 of its original volume and the non-methane components are largely eliminated.

– At the receiving terminals, LNG is re-gasified to a gaseous state, whence it can be fed as required into the normal gas distribution grid of the importing country.

– Alternatively, it can be stored for future use in insulated tanks or subsurface storages.

– Apart from its obvious applications as a storable & transportable form of NG, LNG has many applications in its own right, particularly as a nonpolluting fuel for aircraft and ground
vehicles.

– Current production from conventional sources is not sufficient to satisfy all demands for NG.

Natural Gas Reserves

– 2 terms are frequently used to express NG reserves: proved reserves & potential resources.

– Proved reserves: Quantities of gas that have been found by the drill. They can be proved by known reservoir characteristics such as: production data, pressure relationships  and
other data, so that volumes of gas can be determined with reasonable accuracy.

– Potential resources: Quantities of NG that are believed to exist in various rocks of the Earth’s crust but haven’t yet been found by the drill. They are future supplies beyond the
proved reserves.

– There has been a huge disparity between “proven” reserves and potential reserves.

– Different methodologies have been used in arriving at estimates of the future potential of NG.

– Some estimates were based on growth curves, extrapolations of past production, exploratory footage drilled & discovery rates.

– Empirical models of gas discoveries and production have also been developed and converted to mathematical models.

– Future gas supplies as a ratio of the amount of oil to be discovered is a method that has been used also.

– Another approach is a volumetric appraisal of the potential undrilled areas. Different limiting assumptions have been made, such as drilling depths, water depths in offshore areas,
economics & technological factors.

– Even in the case of the highly mature and exploited U.S.A., depending upon information sources, the potential remaining gas reserve estimates vary from 650 Tcf to 5,000 Tcf.

– Proved NG reserves in 2000 were about 1,050 Tcf in U.S.A. & 170 Tcf in Canada.

– On the global scale, it is more difficult to give a good estimate of NG reserves.

– Unlike oil reserves that are mostly (80%) found in Organization of Petroleum Exporting Countries (OPEC), major NG reserves are found in the former Soviet Union, Middle East, Asia
Pacific, Africa, North America, Southern & Central America, and Europe.

Types of Natural Gas Resources

– NG classified as: conventional NG, gas in tight sands, gas in tight shales, coal-bed methane, gas in geopressured reservoirs & gas in gas hydrates.

  1. Conventional NG: Either associated or non-associated gas.

Associated or dissolved gas is found with crude oil. Dissolved gas is that portion of the gas dissolved in the crude oil and associated gas (sometimes called gas-cap gas) is free gas in
contact with the crude oil.  All crude oil reservoirs contain dissolved gas and may or may not contain associated gas.

– Non-associated gas is found in a reservoir that contains a minimal quantity of crude oil.

– Some gases are called gas condensates or simply condensates. Although they occur as gases in underground reservoirs, they have a high content of H.C. liquids so they yield
considerable quantities of them on production.

  1. Gases in tight sands: Found in many areas that contain formations generally having porosities of 0.001 to 1 millidarcy (md).

– At higher gas permeabilities, the formations are generally amenable to conventional fracturing and completion methods.

  1. Gases in tight shales: The shale is generally fissile, finely laminated, and varicolored but predominantly black, brown, or greenish-gray.

– Core analysis has determined that the shale itself has up to 12% porosity, however, permeability values are commonly < 1 md.

– It is thought, therefore, that the majority of production is controlled by naturally occurring fractures and is further influenced by bedding planes and jointing.

– Coal-bed methane: methane gas in minable coal beds with depths < 3,000 ft.

– Although the estimated size of the resource base seems significant, the recovery of this type of gas may be limited owing to practical constraints.

– Geopressured reservoirs: In a rapidly subsiding basin area, clays often seal underlying formations and trap their contained fluids. After further subsidence, P & T of the trapped fluids
exceed those normally anticipated at reservoir depth.

– These reservoirs have been found in many parts of the world during the search for oil & gas.

– Gas hydrates: Snow-like solids in which each water molecule forms hydrogen bonds with the four nearest water molecules to build a crystalline lattice structure that traps gas
molecules in its cavities.

– Contains about 170 times NG by volume under standard conditions.

– Because it’s a highly concentrated form of NG and extensive deposits of naturally occurring gas hydrates have been found in various regions of the world, they are considered as a
future, unconventional resource of NG.

read also What is LPG?

Future of the Natural Gas Industry

– The 19th century was a century of coal that supported the initiation of industrial revolution in Europe.

– The 20th century was the century of oil that was the primary energy source to support the growth of global economy.

– Simmons (2000) concluded that energy disruptions should be a “genuine concern“. He suggests that it will likely cause chronic energy shortage as early as 2010.  It will eventually
evolve into a serious energy crunch.

– The way to avoid such a crunch is to expand energy supply and move from oil to NG and eventually to H2.

– NG is the fuel that is superior to other energy sources not only in economic attractiveness but also in environmental concerns.

– At the end of the last century, natural gas took over the position of coal as the number 2 energy source behind oil.

– In 2000, total world energy consumption was slightly below 400 × 1015 Btu. Oil accounted for 39%, while NG & coal provided 23 % & 22 %, respectively of this.

– It is expected that the transition from oil to NG must be made in the early 21 century.  This isn’t only motivated by environmental considerations but also by technological innovations
and refinements.

References:
1. Natural Gas Engineering Handbook, Dr. Boyun Guo and Dr. AIi Ghalambor
2. Natural Gas, by Primož Potočnik.
3. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

What is Natural Gas?

Natural gas is a subcategory of petroleum that is a naturally occurring, complex mixture of hydrocarbons, with a minor amount of inorganic compounds. Geologists and chemists agree that petroleum originates from plants and animal remains that accumulate on the sea/lake floor along with the sediments that form sedimentary rocks. The processes by which the parent organic material is converted into petroleum are not understood.

    Natural Gas is a mixture of gaseous hydrocarbons occurring in reservoirs of porous rock (commonly sand or sandstone) capped by impervious strata. It is often associated with petroleum, with which it has a common origin in the decomposition of organic matter in sedimentary deposits. Natural gas consists largely of methane (CH4) and ethane (C2H6), with also propane (C3H8) and butane (C4H10)(separated for bottled gas), some higher alkanes (C5H12 and above) (used for gasoline), nitrogen (N2) , oxygen (O2), carbon dioxide (CO2), hydrogen sulfide (H2S), and sometimes valuable helium (He). It is used as an industrial and domestic fuel, and also to make carbon-black and chemical synthesis. Natural gas is transported by large pipelines or (as a liquid) in refrigerated tankers. Natural gas is combustible mixture of hydrocarbon gases, and when burned it gives off a great deal of energy. We require energy constantly, to heat our homes, cook our food, and generate our electricity . Unlike other fossil fuels, however, natural gas is clean burning and emits lower levels of potentially harmful byproducts into the air. It is this need for energy that has elevated natural gas to such a level of importance in our society, and in our lives.
The contributing factors are thought to be bacterial action; shearing pressure during compaction, heat, and natural distillation at depth; possible addition of hydrogen from deep-seated sources; presence of catalysts; and time.

Natural gas accumulations in geological traps can be classified as reservoir, field, or pool. A reservoir is a porous and permeable underground formation containing an individual bank of hydrocarbons confined by impermeable rock or water barriers and is characterized by a single natural pressure system. A field is an area that consists of one or more reservoirs all related to the same structural feature.

a pool contains one or more reservoirs in isolated structures. Wells in the same field can be classified as gas wells, condensate wells, and oil wells. Gas wells are wells
with producing gas-oil-ration (GOR) being greater than 100,000 scf/stb, condensate wells are those with producing GOR being less than 100,000 scf/stb but greater than 5,000 scf/stb; and wells with producing GOR being less than 5,000 scf/stb are classified as oil wells.

natural gas components
natural gas components

The Components of Natural Gas

   Although the principal use of natural gas is the production of pipeline quality gas for distribution to residential and industrial consumers for fuel, a number of components in natural gas are often separated from the bulk gas and sold separately.

  1. METHANE
The principal use of methane is as a fuel; it is the dominant constituent of pipeline quality natural gas. Considerable quantities of methane are used as feedstock in
the production of industrial chemicals, principally ammonia and methanol.

 

2. ETHANE
The majority of the ethane used in the United States comes from gas plants, and refineries and imports account for the remainder. In addition to being left in the
gas for use as a fuel, ethane is used for the production of ethylene, the feedstock for polyethylene.
  3. PROPANE
Gas plants produce about 45% of the propane used in the United States, refineries contribute about 44%, and imports account for the remainder. The principal uses
are petrochemical (47%), residential (39%), farm (8%), industrial (4%), and transportation (2%) . A special grade of propane, called HD-5, is sold as fuel.
  4. ETHANE–PROPANE MIX
When NGL is fractionated into various hydrocarbon streams, the butanes along with part of the propane are sometimes separated for use in local markets because
they are transportable by truck. The remaining light ends, an ethane−propane mix (E-P mix), is then pipelined to a customer as a chemical or refining feedstock.
5. ISOBUTANE
Approximately 42% of the United States supply of isobutene comes from gas plants, refineries supply about 5% (this percentage does not include consumption
of isobutane within the refinery), and imports are responsible for about 12%. The remaining isobutane on the market is furnished by isomerization plants that
convert n-butane to isobutane. The three primary markets for isobutane are as a feedstock for MTBE (methyl tertiary butyl ether) production (which is being
phased out), as a feedstock in the production of reformulated gasoline, and as a feedstock for the production of propylene oxide.
  6. n-BUTANE
Gas plant production of n-butane accounts for about 63% of the total supply, refineries contribute approximately 31%, and imports account for the remainder.
Domestic usage of n-butane is predominantly in gasoline, either as a blending component or through isomerization to isobutane. Specially produced mixtures
of butanes and propane have replaced halocarbons as the preferred propellant in aerosols.
  7. NATURAL GAS LIQUIDS
Natural gas liquids (NGL) include all hydrocarbons liquefied in the field or in processing plants, including ethane, propane, butanes, and natural gasoline. Such
mixtures generated in gas plants are usually referred to as “Y-grade” or “raw product.”
  8 NATURAL GASOLINE
Natural gasoline, a mixture of hydrocarbons that consist mostly of pentanes and heavier hydrocarbons and meet GPA product specifications, should not be confused
with natural gas liquids (NGL), a term used to designate all hydrocarbon liquids produced in field facilities or in gas plants.
The major uses of natural gasoline are in refineries, for direct blending into gasoline and as a feedstock for C5/C6 isomerization. It is used in the petrochemical
industry for ethylene production.
  9. SULFUR
Current sulfur production in the United States is approximately 15,000 metric tons per day (15 MMkg/d); about 85% comes from gas processing plants that
convert H2S to elemental sulfur. Some major uses of sulfur include rubber vulcanization, production of sulfuric acid, and manufacture of black gunpowder

 References:
1. Natural Gas Engineering Handbook, Dr. Boyun Guo and Dr. AIi Ghalambor
2. Natural Gas, by Primož Potočnik.
3. Fundamentals of Natural Gas, Arthur J. Kidnay & William R. Parrish

Well Logs

by Ahmed Imad  

Well log is a continuous record of measurement made in bore hole respond to variation in some physical properties of rocks through which the bore hole is drilled. Traditionally Logs are display on girded papers shown in figure1. Now a days the log may be taken as films, images, and in digital format.

 

HISTORY

  •   1912 Conrad Schlumberger give the idea of using electrical measurements to map subsurface rock bodies.
  •    in 1919 Conrad Schlumberger and his brother Marcel begin work on well logs.

    Logging Unit
    Logging Unit
  •    The first electrical resistivity well log was taken in France, in 1927.
  •    The instrument which was used for this purpose is called SONDE, the sound was stopped at periodic intervals in bore hole and the and resistivity was plotted on graph paper.
  •    In 1929 the electrical resistivity logs are introduce on commercial scale in Venezuela, USA and Russia
  •    For correlation and identification of Hydrocarbon bearing strata.
  •    The photographic – film recorder was developed in 1936 the curves were SN,LN AND LAT
  •    The dip meter log were developed in 1930
  • the Gamma ray and Neutron Log were began in 1941.

       LOGGING UNITS

  •     logging cable
  •     winch to raise and lower the cable in the well
  •     self-contained 120-volt AC generator
  •     set of surface control panels
  •     set of downhole tools (sondes and cartridges)
  •    digital recording system

GR (gamma ray) logs measure radioactivity to determine what types of rocks are present in the well. Because shales contain radioactive elements, they emit lots of
gamma rays. On the other hand, clean sandstones emit very few gamma rays.

SP (spontaneous potential) logs indicate the permemabilities of rocks in the well by measuring the amount of electrical current generated between the drilling fluid and the formation water that is held in pore spaces of the reservoir rock. Porous sandstones with high permeabilities tend to generate more electricity than impermeable shales. Thus, SP logs are often used to tell sandstones from shales

Resistivity logs determine what types of fluids are present in the reservoir rocks by measuring how effective these rocks are at conducting electricity. Because fresh water and oil are poor conductors of electricity they have high resistivities. By contrast, most formation waters are salty enough that they conduct electricity with ease. Thus, formation waters generally have low resistivities. There are many different types of resistivity logs, which results in a confusing array of acronyms.

BHC (borehole compensated) logs, also called sonic logs, determine porosity by measuring how fast sound waves travel through rocks in the well. In general, sound waves travel faster through high-density shales than through lower-density sandstones.

 FDC (formation density compensated) logs, also called density logs, determine porosity by measuring the density of the rocks. Because these logs overestimate the porosity of rocks that contain gas they result in “crossover” of the log curves when paired with Neutron logs (described under CNL logs below).

  CNL (compensated neutron) logs, also called neutron logs, determine porosity by assuming that the reservoir pore spaces are filled with either water or oil and then measuring the amount of hydrogen atoms (neutrons) in the pores. Because these logs underestimate the porosity of rocks that contain gas they result in “crossover” of the log curves when paired with FDC logs (described above).

NMR (nuclear magnetic resonance) logs may be the well logs of the future. These logs measure the magnetic response of fluids present in the pore spaces of the reservoir rocks. In so doing, these logs measure both porosity and permeability, as well as the types of fluids present in the pore spaces.

  Dipmeter logs determine the orientations of sandstone and shale beds in the well, as well as the orientations of faults and fractures in these rocks. The original dipmeters did this by measuring the resisitivity of rocks on at least four sides of the well hole. Modern dipmeters actually make a detailed image of the rocks on all sides of the well hole. Borehole scanners do this with sonic (sound) waves, whereas FMS (formation microscanner) and FMI (formation micro-imager) logs do this by measuring the resisitisvity. These modern, essentially 3D logs are known as image logs since they provide a 360°ree; image of the bore hole that can show bedding features, faults and fractures, and even sedimentary structures, in addition to providing basic dipmeter data on the orientations of bedding.

  References:

 1-Bassiouni, Z: Theory, Measurement, and Interpretation of Well Logs, SPE Textbook Series
  2-Schlumberger, Log Interpretation Charts, Houston, TX (1995) 
  3-Western Atlas, Log Interpretation Charts, Houston, TX (1992