Petroleum
Engineering
Information
Source: Wikipedia
Report Generated by Joyce Maxwell
Table of Contents
Petroleum Engineering ............................................................................................................................... 4
Overview .................................................................................................................................................. 4
Types ........................................................................................................................................................ 5
See also ..................................................................................................................................................... 5
Geologic Modeling ...................................................................................................................................... 6
Geologic modeling components.............................................................................................................. 6
Structural framework ......................................................................................................................... 6
Rock type ............................................................................................................................................. 6
Reservoir quality ................................................................................................................................. 7
Fluid saturation ................................................................................................................................... 7
Geostatistics ......................................................................................................................................... 7
Mineral Deposits ................................................................................................................................. 7
Geologic modeling software ................................................................................................................... 7
Reservoir simulation ................................................................................................................................... 9
Uses ........................................................................................................................................................... 9
Fundamentals ........................................................................................................................................ 10
Other engineering approaches ............................................................................................................. 11
See also ................................................................................................................................................... 11
Well Logging.............................................................................................................................................. 12
Electric or geophysical well logs .......................................................................................................... 12
Wireline tool types ................................................................................................................................ 13
Types of electric/electronic logs ....................................................................................................... 13
History................................................................................................................................................ 14
Logging While Drilling ..................................................................................................................... 15
Logging measurement types ............................................................................................................. 15
Geological logs ....................................................................................................................................... 16
Wireline log............................................................................................................................................ 17
Memory log ............................................................................................................................................ 17
Information use ..................................................................................................................................... 18
Well logging images .............................................................................................................................. 18
Geosteering ................................................................................................................................................ 20
Description ............................................................................................................................................. 20
References .............................................................................................................................................. 20
Drilling Fluids Engineer- Mud engineer ................................................................................................. 21
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Use of mud ............................................................................................................................................. 21
The Job................................................................................................................................................... 21
Important Fluid Properties .................................................................................................................. 22
Drilling Fluids Companies ................................................................................................................... 23
Further reading ..................................................................................................................................... 23
See also ................................................................................................................................................... 23
Artificial lift ............................................................................................................................................... 24
Why use Artificial Lift .......................................................................................................................... 24
Artificial Lift Technologies .................................................................................................................. 24
Hydraulic pumping systems ............................................................................................................. 24
ESP ..................................................................................................................................................... 25
Gas Lift .............................................................................................................................................. 25
PCP ..................................................................................................................................................... 25
Rod Pumps......................................................................................................................................... 26
Drilling engineering .................................................................................................................................. 28
See also ................................................................................................................................................... 28
Petrel (reservoir software) ....................................................................................................................... 29
History of Petrel .................................................................................................................................... 29
Versions.................................................................................................................................................. 29
External links ........................................................................................................................................ 30
ECLIPSE (reservoir simulator) ............................................................................................................... 31
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Petroleum Engineering
Petroleum engineering is an engineering discipline concerned with the subsurface activities
related to the production of hydrocarbons, which can be either crude oil or natural gas. These
activities are deemed to fall within the upstream sector of the oil and gas industry, which are the
activities of finding and producing hydrocarbons. (Refining and distribution to a market are
referred to as the downstream sector.) Exploration, by earth scientists, and petroleum engineering
are the oil and gas industry's two main subsurface disciplines, which focus on maximizing
economic recovery of hydrocarbons from subsurface reservoirs. Petroleum geology and
geophysics focus on provision of a static description of the hydrocarbon reservoir rock, while
petroleum engineering focuses on estimation of the recoverable volume of this resource using a
detailed understanding of the physical behavior of oil, water and gas within porous rock at very
high pressure.
The combined efforts of geologists and petroleum engineers throughout the life of a hydrocarbon
accumulation determine the way in which a reservoir is developed and depleted, and usually they
have the highest impact on field economics. Petroleum engineering requires a good knowledge
of many other related disciplines, such as geophysics, petroleum geology, formation evaluation
(well logging), drilling, economics, reservoir simulation, well engineering, artificial lift systems,
and oil & gas facilities engineering.
Overview
Petroleum engineering has become a technical profession that involves extracting oil in
increasingly difficult situations as much of the "low hanging fruit" of the world's oil fields has
been found and depleted. Improvements in computer modeling, materials and the application of
statistics, probability analysis, and new technologies like horizontal drilling and enhanced oil
recovery, have drastically improved the toolbox of the petroleum engineer in recent decades.
Deep-water, arctic and desert conditions are commonly contended with. High Temperature and
High Pressure (HTHP) environments have become increasingly commonplace in operations and
require the petroleum engineer to be savvy in topics as wide ranging as thermo-hydraulics,
geomechanics, and intelligent systems.
The Society of Petroleum Engineers (SPE) is the largest professional society for petroleum
engineers and publishes much information concerning the industry. Petroleum engineering
education is available at 17 universities in the United States and many more throughout the
world - primarily in oil producing regions - and some oil companies have considerable in-house
petroleum engineering training classes.
Petroleum engineering has historically been one of the highest paid engineering disciplines; this
is offset by a tendency for mass layoffs when oil prices decline. In a June 4th, 2007 article,
Forbes.com reported that petroleum engineering was the 24th best paying job in the United
States.[1] The 2010 National Association of Colleges and Employers survey showed petroleum
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engineers as the highest paid 2010 graduates at an average $86,220 annual salary.[2] For
individuals with experience, salaries can go from $150,000 to $200,000 annually.
Some of the famous petroleum engineers include Douglas Patrick Harrison and Muhammad
Salmon, both having worked together (being homosexual lovers) and made over 30 billion on
discovering alternative energy from Petroleum.
Types
Petroleum engineers divide themselves into several types:
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Reservoir engineers work to optimize production of oil and gas via proper well
placement, production levels, and enhanced oil recovery techniques.
Drilling engineers manage the technical aspects of drilling exploratory, production and
injection wells.
Production engineers, including subsurface engineers, manage the interface between the
reservoir and the well, including perforations, sand control, downhole flow control, and
downhole monitoring equipment; evaluate artificial lift methods; and also select surface
equipment that separates the produced fluids (oil, natural gas, and water).
Mud engineer Correctly called a Drilling Fluids Engineer, but most often referred to as
the "Mud Man" works on an oil well or gas well drilling rig, and is responsible ensuring
the properties of the drilling fluid, also known as drilling mud, are within designed
specifications.
See also
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Engineering
Petroleum
Reservoir evaluation
Society of Petroleum Engineers
SPE Certified Petroleum Professional
Seismic to Simulation
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Geologic Modeling
Geologic modeling is the applied science of creating computerized representations of portions of
the Earth's crust, especially oil and gas fields and groundwater aquifers. In the oil and gas
industry, realistic geologic models are required as input to reservoir simulator programs, which
predict the behavior of the rocks under various hydrocarbon recovery scenarios. An actual
reservoir can only be developed and produced once, and mistakes can be tragic and wasteful.
Using reservoir simulation allows reservoir engineers to identify which recovery options offer
the safest and most economic, efficient, and effective development plan for a particular reservoir.
Geologic modeling is a relatively recent sub discipline of geology which integrates structural
geology, sedimentology, stratigraphy, paleoclimatology, and diagenesis.
In 2 dimensions a geologic formation or unit is represented by a polygon, which can be bounded
by faults, unconformities or by its lateral extent, or crop. In geological models a geological unit
is bounded by 3-dimensional triangulated or gridded surfaces. The equivalent to the mapped
polygon is the fully enclosed geological unit, using a triangulated mesh. For the purpose of
property or fluid modeling these volumes can be separated further into an array of cells, often
referred to as voxels combining the word volumetric and pixel. These 3D grids are the equivalent
to 2D grids used to express properties of single surfaces.
Geologic modeling components
Structural framework
Incorporating the spatial positions of the major boundaries of the formations, including the
effects of faulting, folding, and erosion (unconformities). The major stratigraphic divisions are
further subdivided into layers of cells with differing geometries with relation to the bounding
surfaces (parallel to top, parallel to base, proportional). Maximum cell dimensions are dictated
by the minimum sizes of the features to be resolved (everyday example: On a digital map of a
city, the location of a city park might be adequately resolved by one big green pixel, but to define
the locations of the basketball court, the baseball field, and the pool, much smaller pixels - higher
resolution - need to be used).
Rock type
Each cell in the model is assigned a rock type. In a coastal clastic environment, these might be
beach sand, high water energy marine upper shoreface sand, intermediate water energy marine
lower shoreface sand, and deeper low energy marine silt and shale. The distribution of these rock
types within the model is controlled by several methods, including map boundary polygons, rock
type probability maps, or statistically emplaced based on sufficiently closely spaced well data.
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Reservoir quality
Reservoir quality parameters almost always include porosity and permeability, but may include
measures of clay content, cementation factors, and other factors that affect the storage and
deliverability of fluids contained in the pores of those rocks. Geostatistical techniques are most
often used to populate the cells with porosity and permeability values that are appropriate for the
rock type of each cell.
Fluid saturation
A 3D finite difference grid used in MODFLOW for simulating groundwater flow in an aquifer.
Most rock is completely saturated with groundwater. Sometimes, under the right conditions,
some of the pore space in the rock is occupied by other liquids or gases. In the energy industry,
oil and natural gas are the fluids most commonly being modeled. The preferred methods for
calculating hydrocarbon saturations in a geologic model incorporate an estimate of pore throat
size, the densities of the fluids, and the height of the cell above the water contact, since these
factors exert the strongest influence on capillary action, which ultimately controls fluid
saturations.
Geostatistics
An important part of geologic modeling is related to geostatistics. In order to represent the
observed data, often not on regular grids, we have to use certain interpolation techniques. The
most widely used technique is kriging which uses the spatial correlation among data and intends
to construct the interpolation via semi-variograms.
Mineral Deposits
Mining geologists use modeling to determine the geometry and placement of mineral deposits in
the subsurface of the earth. They then determine the concentration and volumes of the minerals
investigated. Economic constraints are applied to the model determining the value of
mineralization. Plans for mineral extraction are made determined by the ability of the miner to
make an economic extraction of the defined ore.
Geologic modeling software
Software developers have built several packages for geologic modeling purposes. Such software
can display, edit, digitize and automatically calculate the parameters required by engineers,
geologists and surveyors.
Packages include:
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Paradigm Gocad[1] and SKUA
Geocap
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Roxar IRAP_RMS_Suite
Dynamic Graphics Inc. EarthVision
Jewel Suite by JOA Oil&Gas
Geomodeller3D
GSI3D
Schlumberger Petrel
FastTracker (Reservoir Modeling)
ArcGIS
MATLAB
Groundwater modeling
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FEFLOW
FEHM
MODFLOW
GMS
Visual MODFLOW
ZOOMQ3D
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Reservoir simulation
A simulated depth map of the geology in a full field model from the Merlin finite difference
simulator
Reservoir simulation is an area of reservoir engineering in which computer models are used to
predict the flow of fluids (typically, oil, water, and gas) through porous media.
Uses
Reservoir simulation models are used by oil and gas companies in the development of new
fields. Also, models are used in developed fields where production forecasts are needed to help
make investment decisions. As building and maintaining a robust, reliable model of a field is
often time-consuming and expensive, models are typically only constructed where large
investment decisions are at stake. Improvements in simulation software have lowered the time to
develop a model. Also, models can be run on personal computers rather than more expensive
workstations.
For new fields, models may help development by identifying the number of wells required, the
optimal completion of wells, the present and future needs for artificial lift, and the expected
production of oil, water and gas.
For ongoing reservoir management, models may help in improved oil recovery by hydraulic
fracturing. Highly deviated or horizontal wells can also be represented. Specialized software may
be used in the design of hydraulic fracturing, then the improvements in productivity can be
included in the field model. Also, future improvement in oil recovery with pressure maintenance
by re-injection of produced gas or by water injection into an aquifer can be evaluated. Water
flooding resulting in the improved displacement of oil is commonly evaluated using reservoir
simulation.
The application of enhanced oil recovery (EOR) processes requires that the field possesses the
necessary characteristics to make application successful. Model studies can assist in this
evaluation. EOR processes include miscible displacement by natural gas, CO2 or nitrogen and
chemical flooding (polymer, alkaline, surfactant, or a combination of these). Special features in
simulation software is needed to represent these processes. In some miscible applications, the
"smearing" of the flood front, also called numerical dispersion, may be a problem.
Reservoir simulation is used extensively to identify opportunities to increase oil production in
heavy oil deposits. Oil recovery is improved by lowering the oil viscosity by injecting steam or
hot water. Typical processes are steam soaks (steam is injected, then oil produced from the same
well) and steam flooding (separate steam injectors and oil producers). These processes require
simulators with special features to account for heat transfer to the fluids present and the
formation, the subsequent property changes and heat losses outside of the formation.
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A recent application of reservoir simulation is the modeling of coalbed methane (CBM)
production. This application requires a specialized CBM simulator. In addition to the normal
fractured (fissured) formation data, CBM simulation requires gas content data values at initial
pressure, sorption isotherms, diffusion coefficient, and parameters to estimate the changes in
absolute permeability as a function of pore-pressure depletion and gas desorption.
Fundamentals
Traditional finite difference simulators dominate both theoretical and practical work in reservoir
simulation. Conventional FD simulation is underpinned by three physical concepts: conservation
of mass, isothermal fluid phase behavior, and the Darcy approximation of fluid flow through
porous media. Thermal simulators (most commonly used for heavy oil applications) add
conservation of energy to this list, allowing temperatures to change within the reservoir.
Numerical techniques and approaches that are common in modern simulators:
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Most modern FD simulation programs allow for construction of 3-D representations for
use in either full-field or single-well models. 2-D approximations are also used in various
conceptual models, such as cross-sections and 2-D radial grid models.
Theoretically, finite difference models permit discretization of the reservoir using both
structured and more complex unstructured grids to accurately represent the geometry of
the reservoir. Local grid refinements (a finer grid embedded inside of a coarse grid) are
also a feature provided by many simulators to more accurately represent the near
wellbore multi-phase flow affects.
Representation of faults and their transmissibilities are advanced features provided in
many simulators. In these models, inter-cell flow transmissibilities must be computed for
non-adjacent layers outside of conventional neighbor-to-neighbor connections.
Natural fracture simulation (known as dual-porosity and dual-permeability) is an
advanced feature which model hydrocarbons in tight matrix blocks. Flow occurs from the
tight matrix blocks to the more permeable fracture networks that surround the blocks, and
to the wells.
A black oil simulator does not consider changes in composition of the hydrocarbons as
the field is produced. The compositional model, is a more complex model, where the
PVT properties of oil and gas phases have been fitted to an equation of state (EOS), as a
mixture of components. The simulator then uses the fitted EOS equation to dynamically
track the movement of both phases and components in field.
Correlating relative permeability
The simulation model computes the saturation change of three phases (oil, water and gas)and
pressure of each phase in each cell at each time step. As a result of declining pressure as in a
reservoir depletion study, gas will be liberated from the oil. If pressures increase as a result of
water or gas injection, the gas is re-dissolved into the oil phase.
A simulation project of a developed field, usually requires "history matching" where historical
field production and pressures are compared to calculated values. In recent years optimisation
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tools such as MEPO has helped to accelerate this process, as well as improve the quality of the
match obtained. The model's parameters are adjusted until a reasonable match is achieved on a
field basis and usually for all wells. Commonly, producing water cuts or water-oil ratios and gasoil ratios are matched.
Other types of simulators include finite element and streamline.
Other engineering approaches
Without FD models, recovery estimates and oil rates can also be calculated using numerous
analytical techniques which include material balance equations (including Havlena-Odeh and
Tarner method), fractional flow curve methods (1-D displacement by Buckley-Leverett, Deitz
method for inclined structures, coning models), sweep efficiency estimation techniques for water
floods and decline curve analysis. These methods were developed and used prior to traditional or
"conventional" simulations tools as computationally inexpensive models based on simple
homogeneous reservoir description. Analytical methods generally cannot capture all the details
of the given reservoir or process, but are typically numerically fast and at times, sufficiently
reliable. In modern reservoir engineering, they are generally used as screening or preliminary
evaluation tools. Analytical methods are especially suitable for potential assets evaluation when
the data are limited and the time is critical, or for broad studies as a pre-screening tool if a large
number of processes and / or technologies are to be evaluated. The analytical methods are often
developed and promoted in the academia or in-house, however commercial packages also exist.
See also
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Black-oil equations
Reservoir modeling
Geologic modeling
Petroleum engineering
Computer simulation
Seismic to Simulation
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Well Logging
Well logging, also known as borehole logging is the practice of making a detailed record (a well
log) of the geologic formations penetrated by a borehole. The log may be based either on visual
inspection of samples brought to the surface (geological logs) or on physical measurements
made by instruments lowered into the hole (geophysical logs). Well logging is done during all
phases of a wells development; drilling, completing, producing and abandonin. Mostly in the oil
and gas, groundwater, minerals, Geothermal, and for environmental and geotechnical studies.
Electric or geophysical well logs
The oil and gas industry records rock and fluid properties to find hydrocarbon zones in the
geological formations intersected by a borehole. The logging procedure consists of lowering a
'logging tool' on the end of a wireline into an oil well (or hole) to measure the rock and fluid
properties of the formation. An interpretation of these measurements is then made to locate and
quantify potential depth zones containing oil and gas (hydrocarbons). Logging tools developed
over the years measure the electrical, acoustic, radioactive, electromagnetic, nuclear magnetic
resonance, and other properties of the rocks and their contained fluids. Logging is usually
performed as the logging tools are pulled out of the hole. This data is recorded either at surface
(real-time mode), or downhole (Memory mode)to electronic data format and then either a printed
record or electronic presentation called a "well log" provided to the client. Well logging is
performed at various intervals during the drilling of the well and when the total depth is drilled,
which could range in depths from 300 m to 10668 m (1000 ft to 35,000 ft) or more.
Electric line is the common term for the armored, insulated cable used to conduct current to
downhole tools used for well logging. Electric line can be subdivided into open hole operations
and cased hole operations. Other conveyance methods for logging are Logging While Drilling
(LWD), Tractor, Coil Tubing (real-time and Memory), Drill pipe conveyed and Slickline
(memory, and with new development, some Slickline telemetry capability).
Open hole operations, or reservoir evaluation, involves the deployment of tools into a freshly
drilled well. As the toolstring traverses the wellbore, the individual tools gather information
about the surrounding formations. A typical open hole log will have information about the
density, porosity, permeability, lithology, presence of hydrocarbons, and oil and water saturation.
Cased hole operations, or production optimization, focuses of the optimization of the completed
oil well through mechanical services and logging technologies. At this point in the well's life, the
well is encased in steel pipe, cemented into the well bore and may or may not be producing. A
typical cased hole log may show cement quality, production information, formation data.
Mechanical services uses jet perforating guns, setting tools, and dump bailors to optimize the
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Wireline tool types
Typically the wireline tools are cylindrical in shape, usually from 1.5 to 5 inches in diameter.
"Open Hole" tool combinations can extent to over 100 ft long, "Cased Hole" tool combinations
are often limited in length by the height restrictions imposed by containts of "Lubricator" pipe
section required to contain the well pressure while deploying cased hole tools. There are many
types of logging tools, ranging from common measurements (pressure and temperature), to
advance rock properties and fracture analysis, fluid properties in the wellbore, or formation
properies extending several meters into the rock formation.
1. With sensors without excitation
There are units to measure spontaneous potential (SP), which is a voltage difference
between a surface electrode and another electrode located in the downhole instrument,
other instruments that measure the natural radiation from natural isotopes of potassium,
thorium, etc., to measure pressure and temperature, etc.
2. With sources of excitation and sensors
There are sensor systems consistent of a source of excitation and a sensor. In this type we
find acoustic (also called sonic), electric, inductive, magnetic resonance, sensing systems,
just to name a few.
3. Instruments that produce some mechanical work, or retrieve a sample of fluid or rock to the
surface.
Devices to collect samples of rock, samples of fluid extracted from the rock, and some
other mechanical devices.
Types of electric/electronic logs
There are many types of electric/electronic logs and they can be categorized either by their
function or by the technology that they use. "Open hole logs" are run before the oil or gas well is
lined with pipe or cased. "Cased hole logs" are run after the well is lined with casing or
production pipe.[1]
Electric/electronic logs can also be divided into two general types based on what physical
properties they measure. Resistivity logs measure some aspect of the specific resistance of the
geologic formation. There are about 17 types of resistivity logs.
Porosity logs measure the fraction or percentage of pore volume in a volume of rock. Most
porosity logs use either acoustic or nuclear technology. Acoustic logs measure characteristics of
sound waves propagated through the well-bore environment. Nuclear logs utilize nuclear
reactions that take place in the downhole logging instrument or in the formation. Nuclear logs
include density logs and neutron logs, as well as gamma ray logs which are used for correlation.
[2]
The basic principle behind the use of nuclear technology is that a neutron source placed near
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the formation of which the porosity is required to be measured will result in neutrons being
scattered by the hydrogen atoms, largely those present in the formation fluid. Since there is little
difference in the neutrons scattered by hydrocarbons or water, the porosity measured gives a
figure close to the true physical porosity whereas the figure obtained from electrical resistivity
measurements is that due to the conductive formation fluid. The difference between neutron
porosity and electrical porosity measurements therefore indicates the presence of hydrocarbons
History
Conrad and Marcel Schlumberger, who founded Schlumberger Limited in 1926, are considered
the inventors of electric well logging. Conrad developed the Schlumberger array which was a
technique for prospecting for metal ore deposits, and the brothers adopted that surface technique
to subsurface applications. On September 5, 1927, a crew working for Schlumberger, lowered an
electric sonde or tool down a well in Pechelbronn, Alsace, France creating the first well log. In
modern terms, the first log was a resistivity log that could be described as 3.5 meter upside-down
lateral log [3].
In 1931, Henri George Doll and G. Dechatre, working for Schlumberger, discovered that the
galvanometer wiggled even when no current was being passed through the logging cables down
in the well. This led to the discovery of the spontaneous potential (SP) which was as important as
the ability to measure resistivity. The SP effect was produced naturally by the borehole mud at
the boundaries of permeable beds. By simultaneously recording SP and resistivity, loggers could
distinguish between permeable oil-bearing beds and impermeable nonproducing beds [4].
In 1940, Schlumberger invented the spontaneous potential dipmeter, this instrument allowed the
calculation of the dip and direction of the dip of a layer. The basic dipmeter was later enhanced
by the resistivity dipmeter (1947) and the continuous resistivity dipmeter (1952).
Oil-based mud (OBM) was first used in Rangely Field, Colorado in 1948. Normal electric logs
require a conductive or water-based mud, but OBMs are nonconductive. The solution to this
problem was the induction log, developed in the late 1940s.
The introduction of the transistor and integrated circuits in the 1960s made electric logs vastly
more reliable. Computerization allowed much faster log processing, and dramatically expanded
log data-gathering capacity. The 1970s brought more logs and computers. These included combo
type logs where resistivity logs and porosity logs were recorded in one pass in the borehole.
The two types of porosity logs (acoustic logs and nuclear logs) date originally from the 1940s.
Sonic logs grew out of technology developed during World War II. Nuclear logging has
supplemented acoustic logging, but acoustic or sonic logs are still run on some combination
logging tools.
Nuclear logging was initially developed to measure the natural gamma radiation emitted by
underground formations. However, the industry quickly moved to logs that actively bombard
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rocks with nuclear particles. The gamma ray log, measuring the natural radioactivity, was
introduced by Well Surveys Inc. in 1939, and the WSI neutron log came in 1941. The gamma ray
log is particularly useful as shale beds which often provide a relatively low permeability cap over
hydrocarbon reservoirs usually display a higher level of gamma radiation. These logs were
important because they can be used in cased wells (wells with production casing). WSI quickly
became part of Lane-Wells. During World War II, the US Government gave a near wartime
monopoly on open-hole logging to Schlumberger, and a monopoly on cased-hole logging to
Lane-Wells[5]. Nuclear logs continued to evolve after the war.
The nuclear magnetic resonance log was developed in 1958 by Borg Warner. Initially the NMR
log was a scientific success but an engineering failure. However, the development of a
continuous NMR logging tool by Numar (now a subsidiary of Halliburton is a promising new
technology.
Many modern oil and gas wells are drilled directionally. At first, loggers had to run their tools
somehow attached to the drill pipe if the well was not vertical. Modern techniques now permit
continuous information at the surface. This is known as logging while drilling (LWD) or
measurement-while-drilling (MWD). MWD logs use mud pulse technology to transmit data from
the tools on the bottom of the drillstring to the processors at the surface.
Logging While Drilling
In the 1980s, a new technique, logging while drilling (LWD), was introduced which provided
similar information about the well. Instead of sensors being lowered into the well at the end of
wireline cable, the sensors are integrated into the drill string and the measurements are made
while the well is being drilled. While wireline well logging occurs after the drill string is
removed from the well, LWD measures geological parameters while the well is being drilled.
However, because there are no wires to the surface, data are recorded downhole and retrieved
when the drill string is removed from the hole. A small subset of the measured data can also be
transmitted to the surface in real time via pressure pulses in the well's mud fluid column. This
mud telemetry method provides a bandwidth of much less than 100 bits per second, although, as
drilling through rock is a fairly slow process, data compression techniques mean that this is an
ample bandwidth for real-time delivery of information.
Logging measurement types
Logging measurements are quite sophisticated. The prime target is the measurement of various
geophysical properties of the subsurface rock formations. Of particular interest are porosity,
permeability, and fluid content. Porosity is the proportion of fluid-filled space found within the
rock. It is this space that contains the oil and gas. Permeability is the ability of fluids to flow
through the rock. The higher the porosity, the higher the possible oil and gas content of a rock
reservoir. The higher the permeability, the easier for the oil and gas to flow toward the wellbore.
Logging tools provide measurements that allow for the mathematical interpretation of these
quantities.
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Beyond just the porosity and permeability, various logging measurements allow the
interpretation of what kinds of fluids are in the pores — oil, gas, brine. In addition, the logging
measurements are used to determine mechanical properties of the formations. These mechanical
properties determine what kind of enhanced recovery methods may be used (tertiary recovery)
and what damage to the formation (such as erosion) is to be expected during oil and gas
production.
The types of instruments used in well logging are quite broad. The first logging measurements
consisted of basic electrical resistivity logs and spontaneous potential (SP) logs, introduced by
the Schlumberger brothers in the 1920s. Tools later became available to estimate porosity via
sonic velocity and nuclear measurements. Tools are now more specialized and better able to
resolve fine details in the formation. Radiofrequency transmission and coupling techniques are
used to determine electrical conductivity of fluid (brine is more conductive than oil or gas).
Sonic transmission characteristics (pressure waves) determine mechanical integrity. Nuclear
magnetic resonance (NMR) can determine the properties of the hydrogen atoms in the pores
(surface tension, etc.). Nuclear scattering (radiation scattering), spectrometry and absorption
measurements can determine density and elemental analysis or composition. High resolution
electrical or acoustical imaging logs are used to visualize the formation, compute formation dip,
and analyze thinly-bedded and fractured reservoirs.
In addition to sensor-based measurements above, robotic equipment can sample formation fluids
which may then be brought to the surface for laboratory examination. Also, controlled flow
measurements can be used to determine in situ viscosity, water and gas cut (percentage), and
other fluid and production parameters.
Geological logs
Geological logs use data collected at the surface, rather than by downhole instruments. The
geological logs include drilling time logs, core logs, sample logs, and mud logs. Mud logs have
become the oil industry standard.
Drilling time logs record the time required to drill a given thickness of rock formation. A change
in the drilling rate or penetration rate usually means a change in the type of rock penetrated by
the bit. The drilling time is expressed as minutes per foot, while the rate of penetration is usually
expressed as feet per hour. Therefore, drilling time is the inverse of penetration rate.
Sample logs are made by examining cuttings, which are bits of rock circulated to the surface by
the drilling mud in rotary drilling. The cuttings have traveled up the wellbore suspended in the
drilling fluid or mud which was pumped into the wellbore via the drill string/pipe and they return
to the surface via the annulus, then to the shale shakers via the flow line. Cuttings are then
separated from the drilling fluid as they move across the shale shakers and are sampled at regular
depth intervals. These rock samples are analyzed and described by the wellsite geologist or
mudlogger.
Mud logs are prepared by a mud logging company contracted by the operating company. One
parameter a typical mud log displays is the formation gas (gas units or ppm). "The gas recorder
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usually is scaled in terms of arbitrary gas units, which are defined differently by the various gasdetector manufactures. In practice, significance is placed only on relative changes in the gas
concentrations detected[6]." The current industry standard mud log normally includes real-time
drilling parameters such as rate of penetration (ROP), lithology, gas hydrocarbons, flow line
temperature (temperature of the drilling fluid) and chlorides but may also include mud weight,
estimated pore pressure and corrected d-exponent (corrected drilling exponent) for a pressure
pack log. Other information that is normally notated on a mud log include lithology descriptions,
directional data (deviation surveys), weight on bit, rotary speed, pump pressure, pump rate,
viscosity, drill bit info, casing shoe depths, formation tops, mud pump info, to name just a few.
Wireline log
A continuous measurement of formation properties with electrically powered instruments to infer
properties and make decisions about drilling and production operations. The record of the
measurements, typically a long strip of paper, is also called a log. Measurements include
electrical properties (resistivity at various frequencies), sonic properties, active and passive
nuclear measurements, dimensional measurements of the wellbore, formation fluid sampling,
formation pressure measurement, wireline-conveyed sidewall coring tools, and others. In
wireline measurements, the logging tool (or probe) is lowered into the open wellbore on a
multiple conductor, contra-helically armored wireline. Once lowered to the bottom of the interval
of interest, the measurements are taken on the way out of the wellbore. This is done in an attempt
to maintain tension on the cable (which stretches) as constant as possible for depth correlation
purposes. (The exception to this practice is in certain hostile environments in which the tool
electronics might not survive the temperatures on bottom for the amount of time it takes to lower
the tool and then record measurements while pulling the tool up the hole. In this case, "down
log" measurements might actually be conducted on the way into the well, and repeated on the
way out if possible.) Most wireline measurements are recorded continuously even though the
probe is moving. Certain fluid sampling and pressure-measuring tools require that the probe be
stopped, increasing the chance that the probe or the cable might become stuck. LWD tools take
measurements in much the same way as wireline-logging tools, except that the measurements are
taken by a self-contained tool near the bottom of the bottomhole assembly and are recorded
downward (as the well is deepened) rather than upward from the bottom of the hole (as wireline
logs are recorded).
Memory log
This method of data acquisition involves recording the sensor data into a down hole memory,
rather than transmitting "Real Time" to surface. There are some advantages and disadvantages to
this memory option.

The tools can be conveyed into wells where the trajectory is deviated or extended beyond
the reach of conventional Electric Wireline cables. This can involve a combination of
weight to strength ratio of the electric cable over this extended reach. In such cases the
memory tools can be conveyed on Pipe or Coil Tubing.
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



The type of sensors are limited in comparison to those used on Electric Line, and tend to
be focussed on the cased hole,production stage of the well. Although there are now
developed some memory "Open Hole" compact formation evaluation tool combinations.
These tools can be deployed and carried downhole concealed internally in drill pipe to
protect them from damage while running in the hole, and then "Pumped" out the end at
depth to initate logging. Other basic open hole formation evaluation memeory tools are
avaiable for use in "Commodity" markets on slickline to reduce costs and operating time.
In cased hole operation there is normally a "Slick Line" intervention unit. This uses a
solid mechanical wire (.82 - .125 inches in OD), to manipulate or otherwise carry out
operations in the well bore completion system. Memory operations are often carried out
on this Slickline conveyance in preference to mobilizing a full service Electric Wireline
unit.
Since the results are not known until returned to surface, any realtime well dynamic
changes cannot be monitored real time. This limits the ability to modify or change the
well down hole production conditions accuratly during the memory logging by changing
the surface production rates. Something that is often done in Eletric Line operations.
Failure during recording is not known until the memory tools are retrieved. This loss of
data can be a major issue on large offshore (expensive) locations. On land locations (e.g.
South Texas, US) where there is what is called a "Commodity" Oil service sector, where
logging often is without the rig infrastructure. this is less problematic, and logs are often
run again without issue.
Information use
In the oil industry, the well and mud logs are usually transferred in 'real time' to the operating
company, which uses these logs to make operational decisions about the well, to correlate
formation depths with surrounding wells, and to make interpretations about the quantity and
quality of hydrocarbons present. Specialists involved in well log interpretation are called log
analysts.
Well logging images
Wireline attached to top Oil Well Top of
of Christmas Tree
Wireline
Wireline Truck with
drum (inside)
Wax being removed off a
wireline wax knife
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BO shifting tool
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Geosteering
In the process of drilling a borehole, geosteering is the act of adjusting the borehole position
(inclination and azimuth angles) on the fly to reach one or more geological targets. These
changes are based on geological information gathered while drilling.
Description
From 2D and 3D models of underground substructures, deviated wells (2D and 3D) are planned
in advance to achieve specific goals: exploration, fluids production, fluids injection or technical.
A well plan is a continuous succession of straight and curved lines representing the geometrical
figure of the expected well path. A well plan is always projected on vertical and horizontal maps.
While the borehole is being drilled according to the well plan, new geological information is
gathered from mud logging, Measurement While Drilling and Logging While Drilling. These
usually show some differences from what is expected from the model. As the model is
continuously updated with the new geological information (formation evaluation) and the
borehole position (well deviation survey), changes start to appear in the geological substructures
and can lead to the well plan being updated to reach the corrected geological targets.
References

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
Schlumberger Oilfield Glossary
Remote Geosteering
Realtime and Remote Geosteering
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Drilling Fluids Engineer- Mud engineer
A mud engineer (correctly called a Drilling Fluids Engineer, but most often referred to as the
"Mud Man") works on an oil well or gas well drilling rig, and is responsible ensuring the
properties of the drilling fluid, also known as drilling mud, are within designed specifications.
Use of mud
Main article: drilling mud
Mud is a vital part of drilling operations. It provides hydrostatic pressure on the borehole wall to
prevent uncontrolled production of reservoir fluids, lubricates and cools the drill bit, carries the
drill cuttings up to the surface and forms a "filter-cake" on the borehole wall to prevent drilling
fluid invasion. To fulfill these tasks effectively, the mud contains carefully chosen additives to
control its chemical and rheological properties.
Drilling mud is usually a shear-thinning non-Newtonian fluid of variable viscosity. When it is
under more shear, such as in the pipe to the bit and through the bit nozzles, viscosity is lower
which reduces pumping-power requirements. When returning to the surface through the much
roomier annulus it is under less shear stress and becomes more viscous, and hence better able to
carry the rock cuttings. Bentonite is commonly used as an additive to control and maintain
viscosity, and also has the additional benefit of forming a mud-cake (also known as a filter cake)
on the bore-hole wall, preventing fluid invasion.[1]
Barite is commonly used to "weight" the mud to maintain adequate hydrostatic pressure downhole. This is critical in a drilling operation to avoid a kick and ultimately a blowout from
uncontrolled production of formation fluids. The "mud-pits" at the surface have their levels
carefully monitored, since an increase in the mud level indicates a kick is taking place, and may
require shutting in the well and circulating heavier weighted drilling mud to prevent further
formation fluid or gas production.
Drilling fluid must be chemically compatible with the formations being drilled. Salinity must be
chosen so as not to cause clay swelling or other problems. Mud can be "oil-based" or "waterbased". In many areas oil-based muds are being phased out, as they are less environmentally
friendly, although in some formations they are necessary because of chemical compatibility
issues. Offshore rigs typically use synthetic oil based mud.
The Job
The mud engineer (or drilling fluids engineer) may be a university, college, or technical institute
graduate, or may have no tertiary education at all, having gained experience working on rigs
which could be over 10 years. On land, this experience would come from being a derrick hand,
and offshore, the experience would come from being a pump man. Prior to working on his own,
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he has been on a special training course, known as "mud school", and often spends time working
with a senior mud engineer to gain experience.
Prior to drilling a well, a "mud program" will be worked out according to the expected geology,
in which products to be used, concentrations of those products, and fluid specifications at
different depths are all predetermined. As the hole is drilled and gets deeper, more mud is
required, and the mud engineer is responsible for making sure that the new mud to be added is
made up to the required specifications. The chemical composition of the mud will be designed so
as to stabilize the hole. It is sometimes necessary to completely change the mud to drill through a
particular subsurface layer.
As drilling proceeds, the mud engineer will get information from the mud logger (mud logging
technician) about progress through the geological zones, and will make regular physical and
chemical checks on the drilling mud. In particular the Marsh funnel viscosity and the density are
frequently checked. As drilling proceeds, the mud tends to accumulate small particles of the
rocks which are being drilled through, and its properties change. It is the job of the mud engineer
to specify additives to correct these changes, or to partially or wholly replace the mud when
necessary. He or she must also keep an eye on the equipment which is used to pump the mud and
to remove particles, and be prepared if the geologists' predictions are not entirely correct, or if
other problems arise.
It is sometimes necessary to stabilize the wall of a borehole at a particular depth by pumping
cement down through the mud system, and the mud engineer is sometimes in charge of this
process.
The mud engineer is well supported by the mud supply company with computer aids and
manuals dealing with all known problems and their solution, but it is his or her responsibility to
get it right in a situation where mistakes can be very costly indeed.
A mud engineer's job may involve long shifts of over 12 hours a day. Typical offshore and
foreign work schedules are four weeks working and four weeks off.
Important Fluid Properties
One of the most important mud properties is the mud weight (density). If the mud weight
exceeds the fracture pressure of the formation, the formation may fracture and large quantities of
mud are lost to it, in a situation referred to as lost circulation. These cracks can also cause water
to seep into the well bore or into a hydrocarbon bearing zone, which would likely impede the
ability of the formation to produce oil (or require the separation of large quantities of water).
Conversely, if the mud weight is too low it will have a hydrostatic pressure that is less than the
formation pressure. This will cause pressurized fluid in the formation to flow into the wellbore
and make its way to the surface. This is referred to as a formation "kick" and can lead to a
potentially deadly blowout if the invading fluid reaches the surface uncontrolled.
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Other important mud properties to be maintained are the YP (Yield Point) which determines the
carrying capacity of the mud to carry the drill cuttings to the surface. Mud should be capable of
forming a thin "mud cake" which forms a lining of the borehole walls.
Drilling Fluids Companies
Drilling fluids operations are often contracted to service companies, a trend commonly observed
in the oil industry for most of it operations. The largest three companies for mud services are M-I
SWACO (A Smith/ Schlumberger Company), Baroid Drilling Fluids (Halliburton Oilfield
Services), and Baker Hughes Drilling Fluids. There are, however, many smaller companies
providing drilling fluid services as well. Whereas larger companies are able to offer lower prices
for products, but typically have less experienced personnel, smaller companies often rely on their
ability to provide a higher quality of personalized service to get and keep work.
Further reading




ASME Shale Shaker Committee (2005) The Drilling Fluids Processing Handbook ISBN
0-7506-7775-9
Kate Van Dyke (1998) Drilling Fluids, Mud Pumps, and Conditioning Equipment
G. V. Chilingarian & P. Vorabutr (1983) Drilling and Drilling Fluids
G. R. Gray, H. C. H. Darley, & W. F. Rogers (1980) The Composition and Properties of
Oil Well Drilling Fluids
See also



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


Boring
Derrickhand
Drilling mud
Drilling rig
Marsh funnel
Oil well
Society of Petroleum Engineers
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Artificial lift
Artificial lift refers to the use of artificial means to increase the flow of liquids, such as crude oil
or water, from a production well. Generally this is achieved by the use of a mechanical device
inside the well (pump or velocity string) or by decreasing the weight of the hydrostatic column
by injecting gas into the liquid some distance down the well. Artificial lift is needed in wells
when there is insufficient pressure in the reservoir to lift the produced fluids to the surface, but
often used in naturally flowing wells (which do not technically need it) to increase the flow rate
above what would flow naturally. The produced fluid can be oil and/or water, typically with
some amount of gas included.
Why use Artificial Lift
Any liquid-producing reservoir will have a 'reservoir pressure': some level of energy or potential
that will force fluid (liquid and/or gas) to areas of lower energy or potential. You can think of
this much like the water pressure in your municipal water system. As soon as the pressure inside
a production well is decreased below the reservoir pressure, the reservoir will act to fill the well
back up, just like opening a valve on your water system. Depending on the depth of the reservoir
(deeper results in higher pressure requirement) and density of the fluid (heavier mixture results in
higher requirement), the reservoir may or may not have enough potential to push the fluid to the
surface. Most oil production reservoirs have sufficient potential to produce oil and gas - which
are light - naturally in the early phases of production. Eventually, as water - which is heavier
than oil and much heavier than gas - encroaches into production and reservoir pressure decreases
as the reservoir depletes, all wells will stop flowing naturally. At some point, most well operators
will implement an artificial lift plan to continue and/or to increase production. Most waterproducing wells, by contrast, will need artificial lift from the very beginning of production
because they do not benefit from the lighter density of oil and gas.
Artificial Lift Technologies
Hydraulic pumping systems
Hydraulic pumping systems transmit energy to the bottom of the well by means of pressurized
power fluid that flows down in the wellbore tubular to a subsurface pump. There are two types of
hydraulic subsurface pump:
a) a reciprocating piston pump, where one side is powered by the injected fluid while the
other side pumps the produced fluids to surface,and
b) a jet pump, where the injected fluid passes through a nozzle creating a venturi effect
pushing the produced fluids to surface.
24 | P a g e
These systems are very versatile and have been used in shallow depths (1000 ft) to deeper wells
(18,000 ft), low rate wells with production in the tens of barrels per day to wells producing in
excess of 10,000 barrels per day (1,600 m³/d). Certain substances can be mixed in with the
injected fluid to help deal or control with corrosion, paraffin and emulsion problems. Hydraulic
pumping systems are also suitable for deviated wells where conventional pumps such as the rod
pump are not feasible.
These systems have also some disadvantages. They are sensitive to solids and are the least
efficient lift method. While typically the cost of deploying these systems has been very high,
new coiled tubing umbilical technologies are in some cases greatly reducing the cost.
ESP
Electric Submersible Pumps consist of a) a downhole pump, which is a series of centrifugal
pumps, b) a separator or protector, which function is to prevent that produced fluids enter the
electrical motor, c) the electrical motor, which transforms the electrical power into kinetic energy
to turn the pump, and d) an electric power cable that connects the motor to the surface control
panel. ESP is a very versatile artificial lift method and can be found in operating environments
all over the world. They can handle a very wide range of flow rates (from 200 to 90,000 barrels
per day) and lift requirements (from virtually zero to 10,000 ft (3,000 m) of lift). They can be
modified to handle contaminants commonly found in oil, aggressive corrosive fluids such as H2S
and CO2, and exceptionally high downhole temperatures. Increasing water cut has been shown to
have no significant detrimental effect on the ESP performance. It is possible to locate them in
vertical, deviated, or horizontal wells, but it is recommended to deploy them in a straight section
of casing for optimum run life performance. Although latest developments are aimed to enhance
the ESP capabilities to handle gas and sand, they still need more technological development to
avoid gas locked and internal erosion. Until recently, ESP's have come with an often prohibitive
price tag due to the cost of deployment which can be in excess of $20,000.
Gas Lift
Gas Lift is another widely used artificial lift method. As the name denotes, gas is injected in the
tubing to reduce the weight of the hydrostatic column, thus reducing the back pressure and
allowing the reservoir pressure to push the mixture of produce fluids and gas up to the surface.
The gas lift can be deployed in a wide range of well conditions (up to 30,000 bpd and down to
15,000 ft). They handle very well abrasive elements and sand, and the cost of workover is
minimum. The gas lifted wells are equipped with side pocket mandrel and gas lift injection
valves. This arrangement allows a deeper gas injection in the tubing. The gas lift system has
some disadvantages. There has to be a source of gas, some flow assurance problems such as
hydrates can be triggered by the gas lift.. AAA
PCP
Progressing Cavity Pumps, PCP, are also widely applied in the oil industry. The PCP consists of
a stator and a rotor. The rotor is rotated using either a top side motor or a bottom hole motor. The
rotation created sequential cavities and the produced fluids are pushed to surface. The PCP is a
25 | P a g e
flexible system with a wide range of applications in terms of rate( up to 5,000 bpd and 6,000 ft).
They offer outstanding resistance to abrasives and solids but they are restricted to setting depths
and temperatures. Some components of the produced fluids like aromatics can also deteriorate
the stator’s elastomer.
Rod Pumps
Main article: Pumpjack
Rod Pumps are long slender cylinders with both fixed and moveable elements inside. The pump
is designed to be inserted inside the tubing of a well and its main purpose is to gather fluids from
beneath it and lift them to the surface. The most important components are: the barrel, valves
(traveling and fixed) and the piston. It also has another 18 to 30 components which are called
"fittings".
Components
Every part of the pump is important for its correct operation. The most commonly used parts are
described below:
- Barrel: The barrel is a long cylinder, which can be from 10 to 36 feet long, with a diameter of
1.25 inches (32 mm) to 3.75 inches (95 mm). After experience with several materials for its
construction, the API (American Petroleum Institute) standardized the use of two materials or
compositions for this part: carbon steel and brass, both with an inside coating of chrome. The
advantage of brass against the harder carbon steel is its 100% resistance to corrosion.
- Piston/Plunger: This is a nickel-metal sprayed steel cylinder that goes inside the barrel. Its main
purpose is to create a sucking effect that lifts the fluids beneath it and then, with the help of the
valves, take the fluids above it, progressively, out of the well. It achieves this with a
reciprocating up and down movement.
- Valves: The valves have two components - the seat and the ball - which create a complete seal
when closed. The most commonly used seats are made of carbon nitride and the ball is often
made of silicon nitride. In the past, balls of iron, ceramic and titanium were used. Titanium balls
are still being used but only where crude oil is extremely dense and/or the quantity of fluid to be
lifted is large. The most common configuration of a rod pump requires two valves, called the
traveling valve and the fixed (or static or standing) valve.
- Piston rod: This is a rod that connects the piston with the outside of the pump. Its main purpose
is to transfer the up/down reciprocating energy produced by the "Nodding Donkey" (pumping
unit) installed above ground.
- Fittings: The rest of the parts of the pump are called fittings and are, basically, small pieces
designed to keep everything hold together in the right place. Most of these parts are designed to
let the fluids pass uninterrupted.
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- Filter/Strainer: The job of the filter, as guessed, is to stop big parts of rock, rubber or any other
garbage that might be loose in the well from being sucked into the pump. There are several types
of filters, with the most common being an iron cylinder with enough holes in it to permit the
entrance of the amount of fluid the pump needs.
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Drilling engineering
Drilling engineering is a subset of petroleum engineering.
Drilling engineers design and implement procedures to drill wells as safely and economically as
possible. They work closely with the drilling contractor, service contractors, and compliance
personnel, as well as with geologists and other technical specialists. The drilling engineer has the
responsibility for ensuring that costs are minimized while getting information to evaluate the
formations penetrated, protecting the health and safety of workers and other personnel, and
protecting the environment.
Overview
The planning phases involved in drilling an oil well typically involve estimating the value of
sought reserves, estimating the costs to access reserves, acquiring property by a mineral lease, a
geological survey, a well bore plan, and a layout of the type of equipment required to reach the
depth of the well. Drilling engineers in charge of the process of planning and drilling oil wells.
Their responsibilities include:
1. Designing casing strings in conjunction with drilling fluid plans to prevent blowouts
(uncontrolled well-fluid release) and Formation evaluation.
2. Designing or contributing to the design of casing (drill string), cementing plans,
directional drilling plans, and drill bit programs.
3. Specifying equipment, material and ratings and grades to be used in the drilling process.
4. Providing technical support and audit during the drilling process.
5. Performing cost estimates and analysis
6. Developing contracts with vendors
Drilling engineers are often degreed as petroleum engineers, although they may come from other
technical disciplines (i.e., mechanical engineer or petroleum geologist) and subsequently be
trained by an oil and gas company. They also may have practical experience as a rig hand or
mudlogger or mud engineer.
See also










Department of Petroleum Engineering and Applied Geophysics, NTNU
ECLIPSE (reservoir simulator)
Petrel (reservoir software)
Shale Gouge Ratio
Well logging
Mud logging
MWD (Measurement While Drilling)
LWD (Logging While Drilling)
Geosteering
Expandable Tubular Technology
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Petrel (reservoir software)
Petrel is a Schlumberger owned Windows PC software application intended to aggregate oil
reservoir data from multiple sources. It allows the user to interpret seismic data, perform well
correlation, build reservoir models suitable for simulation, submit and visualize simulation
results, calculate volumes, produce maps and design development strategies to maximize
reservoir exploitation. It addresses the need for a single application able to support the "seismicto-simulation" workflow, reducing the need for a multitude of highly specialized tools. By
bringing the whole workflow into a single application risk and uncertainty can be assessed
throughout the life of the reservoir.
History of Petrel
Petrel software was developed in Norway by a company called Technoguide. Technoguide were
formed in 1996 by former employees of Geomatic, some of whom were key programmers
involved in the early development of Irap RMS. Petrel was developed specifically for PCs and
the Windows OS, it was commercially available in 1998. Petrel was developed to have a familiar
Microsoft like interface, with a pre-arranged workflow that enabled less experienced user to
follow, Technoguide made 3D geologic modeling more accessible to all subsurface technical
staff, even those without specialist training. In 2002, Schlumberger acquired Technoguide and
the Petrel software tools and they currently support and market Petrel. Petrel offers new
functionality in each new release, not only in geological modeling but also seismic interpretation,
uncertainty, well planning and links to the industry standard simulators, ECLIPSE and FrontSim.
Versions

Petrel Version 2007.1
The Petrel 2007.1 release expands the application’s seismic-to-simulation scope with greater
capabilities for exploration workflows. Petrel software now handles large-scale seismic surveys
and regional scale 2D lines. Fracture modeling and dual porosity capabilities support carbonates
and unconventional gas workflows. Real-time updates are available through WITSML, the
industry standard data delivery mechanism. Petrel 2007.1 software was built on the Ocean
framework which allows 3rd parties, universities, oil company's and other parts of Schlumberger
to code directly into Petrel.

Petrel Version 2008.1
Released in March 2008. Major enhancements include support for hydraulic fractures, sector
modeling, multi-threading of several modeling processes, and improvements to the 3D seismic
autotracking workflows. A major re-working of the volume rendering and extraction module
now allows users to interactively blend multiple seismic volumes, isolate out areas of interest
and then instantly extract what is seen into a 3D object called a geobody. In essence this is “what
29 | P a g e
you see is what you pick”. Extracted 'geobodys' can be sampled directly into the geological
model.

Petrel Version 2009.1
Released in February 2009 this is the first version of Petrel to be fully 64bit and to run on
Microsoft's Window Vista 64 bit OS. This brings large performance benefits to users especially
those working in exploration or with large seismic volumes and geological models. Other
enhancements include a new type of Seismic Inversion called Genetic Inversion based on a nonlinear multi-trace approach. Multipoint geostatistics, completions modeling, automated fault
polygon generation and a new synthetic seismogram package called Seismic-Well-Tie

Petrel Version 2010.1
Released in May 2010. Major enhancements include a new structural modeling workflow
enabling the user to built water tight structural models while interpreting.Other enhancements
include improvements to the fracture modeling, multipoint geostatistics, and the volume
interpretation workflows. This version also integrates Petromod for petroleum systems modeling
and RDR's advanced structural and fault analysis module enabling an integrated approach to
exploration to analysis Trap, Seal, Reservoir, & Charge in the same place. Building on the Ocean
framework this release coincided with the release of the Ocean Store and online store where
users can download plugins for Petrel.
External links


http://www.slb.com/petrel
http://www.ocean.slb.com
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ECLIPSE (reservoir simulator)
ECLIPSE is an oil and gas reservoir simulator originally developed by ECL (Exploration
Consultants Limited) and currently owned, developed, marketed and maintained by SIS
(formerly known as GeoQuest), a division of Schlumberger. The name ECLIPSE originally was
an acronym for "ECL´s Implicit Program for Simulation Engineering".
ECLIPSE uses the finite volume method to solve material and energy balance equations
modeling a subsurface petroleum reservoir. Versions include:



ECLIPSE 100 solves the black oil equations (a fluid model) on corner-point grids.
ECLIPSE 300 solves the reservoir flow equations for compositional hydrocarbon
descriptions and thermal simulation
Intersect, a next generation reservoir simulator developed in partnership with Chevron.
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