Deviated Well (Directional)

Deviated Well (Directional):
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1) -TVD: True Vertical Depth which is the vertical distance from a point in the well to a point at the rotary table.

2) -TVDss: true Vertical Depth Sub Sea which is the vertical distance from a point in the well to the mean seal level.

3) -MD: Measured Depth (always>TVD)

4) Ө: Angle of inclination which is angle of deviated well with respect to its vertical origin

5) A: Azimuth which is angle of deviated well with respect to Magnetic North
Pole.

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Vertical Well

Vertical Well:

-RT: is the Rotary Table

-MD: is the Measured Depth which is the distance between the rotary table to the end of well.

-KB: is the Kelly Bushing which is the distance between rotary table & the mean seal level (MSL)

-MDss: is the Measured depth sub sea which is the distance between mean sea level (MSL) to the end of well (MDss=MD-KB).

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UT researchers use simple scaling theory to better predict gas production in barnett shale wells

AUSTIN, Texas — Researchers at The University of Texas at Austin have developed a simple scaling theory to estimate gas production from hydraulically fractured wells in the Barnett Shale. The method is intended to help the energy industry accurately identify low- and high-producing horizontal wells, as well as accurately predict how long it will take for gas reserves to deplete in the wells.

Using historical data from horizontal wells in the Barnett Shale formation in North Texas, Tad Patzek, professor and chair in the Department of Petroleum and Geosystems Engineering in the Cockrell School of Engineering; Michael Marder, professor of physics in the College of Natural Sciences; and Frank Male, a graduate student in physics, used a simple physics theory to model the rate at which production from the wells declines over time, known as the "decline curve."

They describe their new model of the decline curve in the paper "Gas production in the Barnett Shale obeys a simple scaling theory," published this week in the Proceedings of the National Academy of Sciences. To test their theory, the researchers analyzed 10 years of gas production data from the Barnett Shale licensed to the university by IHS CERA, a provider of global market and economic information.



The team's estimates were an instrumental part of the comprehensive assessment of Barnett Shale reserves funded by the Alfred P. Sloan Foundation and issued earlier this year by the Bureau of Economic Geology at UT Austin.

Until now, estimates of shale gas production have primarily relied on models established for conventional oil and gas wells, which behave differently from the horizontal wells in gas-rich shales.

The researchers estimate the ultimate gas recovery from a sample of 8,294 horizontal wells in the Barnett Shale will be between 10 trillion and 20 trillion standard cubic feet (scf) during the lifetime of the wells. The study's well sample is made up of about half of the 15,000 existing wells in the Barnett Shale, the geological formation outside Fort Worth that offers the longest production history for hydrofractured horizontal wells in the world.

"With our model at hand, you can better predict how much gas volume is left and how long it will take until that volume will be depleted," Patzek said. "We are able to match historical production and predict future production of thousands of horizontal gas wells using this scaling theory."

"The contributions of shale gas to the U.S. economy are so enormous that even small corrections to production estimates are of great practical significance," Patzek said.

The researchers were surprised by how all of the wells they analyzed adhere to that simple scaling curve.

"By analyzing the basic physics underlying gas recovery from hydrofractured wells, we calculated a single curve that should describe how much gas comes out over time, and we showed that production from thousands of wells follows this curve," Marder said.

Patzek adds: "We are able to predict when the decline will begin. Once decline sets in, gas production goes down rapidly."

The decline of a well happens because of a process called pressure diffusion that causes pressure around a well to drop and gas production to decrease. The time at which gas pressure drops below its initial value everywhere in the rock between hydrofractures is called its interference time. On average, it takes five years for interference to occur, at which point wells produce gas at a far lower rate because the amount of gas coming out over time is proportional to the amount of gas remaining.

Using two parameters — a well's interference time and the original gas in place — the researchers were able to determine the universal decline curve and extrapolate total gas production over time.

The researchers found that the scaling theory accurately predicted the behavior of approximately 2,000 wells in which production had begun to decrease exponentially within the past 10 years. The remaining wells were too young for the model to predict when decreases would set in, but the model enabled the researchers to estimate upper and lower production limits for well lifetime and the amount of gas that will be produced by the wells.

Read more : http://www.geologypage.com/2013/11/ut-researchers-use-simple-scaling.html#ixzz2mXeoFR7b

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drilling rig videos

Drilling 

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Natural Gas .. Exploration

Exploration

The practice of locating natural gas and petroleum deposits has been transformed dramatically in the last 20 years with the advent of extremely advanced, ingenious technology. In the early days of the industry, the only way of locating underground petroleum and natural gas deposits was to search for surface evidence of these underground formations. Those searching for natural gas deposits were forced to scour the earth, looking for seepages of oil or gas emitted from underground before they had any clue that there were deposits underneath. However, because such a low proportion of petroleum and natural gas deposits actually seep to the surface, this made for a very inefficient and difficult exploration process. As the demand for fossil fuel energy has increased dramatically over the past years, so has the necessity for more accurate methods of locating these deposits.

Sources of Data

Technology has allowed for a remarkable increase in the success rate of locating natural gas reservoirs. In this section, it will be outlined how geologists and geophysicists use technology and knowledge of the properties of underground natural gas deposits to gather data that can later be interpreted and used to make educated guesses as to where natural gas deposits exist. However, it must be remembered that the process of exploring for natural gas and petroleum deposits is characteristically an uncertain one, due to the complexity of searching for something that is often thousands of feet below ground.

Geological Surveys

Exploration for natural gas typically begins with geologists examining the surface structure of the earth, and determining areas where it is geologically likely that petroleum or gas deposits might exist. It was discovered in the mid 1800s that ‘anticlinal slopes’ had a particularly increased chance of containing petroleum or gas deposits. These anticlinal slopes are areas where the earth has folded up on itself, forming the dome shape that is characteristic of a great number of reservoirs. By surveying and mapping the surface and sub-surface characteristics of a certain area, the geologist can extrapolate which areas are most likely to contain a petroleum or natural gas reservoir. The geologist has many tools at his disposal to do so, from the outcroppings of rocks on the surface or in valleys and gorges, to the geologic information attained from the rock cuttings and samples obtained from the digging of irrigation ditches, water wells, and other oil and gas wells. This information is all combined to allow the geologist to make inferences as to the fluid content, porosity, permeability, age, and formation sequence of the rocks underneath the surface of a particular area. For example, in the picture shown, a geologist may study the outcroppings of rock to gain insight into the geology of the subsurface areas.

Surface Geology

Source: Anadarko Petroleum Corporation

For more information on geology in general visit the United States Geological Survey.  For more information on petroleum geology visit the American Association of Petroleum Geologists (AAPG). 

Once the geologist has determined an area where it is geologically possible for a natural gas or petroleum formation to exist, further tests can be performed to gain more detailed data about the potential reservoir area. These tests allow for the more accurate mapping of underground formations, most notably those formations that are commonly associated with natural gas and petroleum reservoirs. These tests are commonly performed by a geophysicist, one who uses technology to find and map underground rock formations.

A Seismograph

Source: U.S. Geological Survey

Seismic Exploration

Arguably the biggest breakthrough in petroleum and natural gas exploration came through the use of basic seismology. Seismology refers to the study of how energy, in the form of seismic waves, moves through the Earth's crust and interacts differently with various types of underground formations. In 1855, L. Palmiere developed the first 'seismograph', an instrument used to detect and record earthquakes. This device was able to pick up and record the vibrations of the earth that occur during an earthquake. However, it wasn't until 1921 that this technology was applied to the petroleum industry and used to help locate underground fossil fuel formations.

Placing Geophones

Source: API

The basic concept of seismology is quite simple. As the Earth's crust is composed of different layers, each with its own properties, energy (in the form of seismic waves) traveling underground interacts differently with each of these layers. These seismic waves, emitted from a source, will travel through the earth, but also be reflected back toward the source by the different underground layers. Through seismology, geophysicists are able to artificially create vibrations on the surface and record how these vibrations are reflected back to the surface, revealing the properties of the geology beneath.

An analogy that makes intuitive sense is that of bouncing a rubber ball. A rubber ball that is dropped on concrete will bounce in a much different way than a rubber ball dropped on sand. In the same manner, seismic waves sent underground will reflect off dense layers of rock much differently than extremely porous layers of rock, allowing the geologist to infer from seismic data exactly what layers exist underground and at what depth. While the actual use of seismology in practice is quite a bit more complicated and technical, this basic concept still holds.

Here is a more detailed overview of seismic exploration. 

Seismology in Practice

Source: API

Onshore Seismology

In practice, using seismology for exploring onshore areas involves artificially creating seismic waves, the reflection of which are then picked up by sensitive pieces of equipment called 'geophones' that are embedded in the ground. The data picked up by these geophones is then transmitted to a seismic recording truck, which records the data for further interpretation by geophysicists and petroleum reservoir engineers. The drawing shows the basic components of a seismic crew. The source of seismic waves (in this case an underground explosion) creates that reflect off the different layers of the Earth, to be picked up by geophones on the surface and relayed to a seismic recording truck to be interpreted and logged.
Although the seismograph was originally developed to measure earthquakes, it was discovered that much the same sort of vibrations and seismic waves could be produced artificially and used to map underground geologic formations. In the early days of seismic exploration, seismic waves were

A Seismic Vibrator Truck

Source: Natural Resources Canada

created using dynamite. These carefully planned, small explosions created the requisite seismic waves, which were then picked up by the geophones, generating data to be interpreted by geophysicists, geologists, and petroleum engineers.

Recently, due to environmental concerns and improved technology, it is often no longer necessary to use explosive charges to generate the needed seismic waves. Instead, most seismic crews use non-explosive seismic technology to generate the required data. This non-explosive technology usually consists of a large heavy-wheeled or tracked-vehicle carrying special equipment designed to create a large impact or series of vibrations. These impacts or vibrations create seismic waves similar to those created by dynamite. In the seismic truck shown, the large piston in the middle is used to create vibrations on the surface of the earth, sending seismic waves that are used to generate useful data.

Offshore Seismology

The same sort of process is used in offshore seismic exploration. When exploring for natural gas that may exist thousands of feet below the seabed floor, which may itself be thousands of feet below sea level, a slightly different method of seismic exploration is used. Instead of trucks and geophones, a ship is used to pick up the seismic data and hydrophones are used to pick up seismic waves underwater. These hydrophones are towed behind the ship in various configurations depending on the needs of the geophysicist. Instead of using dynamite or impacts on the seabed floor, the seismic ship uses a large air gun, which releases bursts of compressed air under the water, creating seismic waves that can travel through the Earth's crust and generate the seismic reflections that are necessary.

Offshore Seismic Exploration

Source: U.S. Geological Survey

Magnetometers

In addition to using seismology to gather data concerning the composition of the Earth's crust, the magnetic properties of underground formations can be measured to generate geological and geophysical data. This is accomplished through the use of magnetometers, which are devices that can measure the small differences in the Earth's magnetic field. In the early days of magnetometers, the devices were large and bulky, and only able to survey a small area at a time.

Gravimeters

In addition to using variances in the Earth's magnetic field, geophysicists can also measure and record the difference in the Earth's gravitational field to gain a better understanding of what is underground. Different underground formations and rock types all have a slightly different effect on the gravitational field that surrounds the Earth. By measuring these minute differences with very sensitive equipment, geophysicists are able to analyze underground formations and develop clearer insight into the types of formations that may lie below ground, and whether or not the formations have the potential for containing hydrocarbons like natural gas.

Exploratory Wells

The best way to gain a full understanding of subsurface geology and the potential for natural gas deposits to exist in a given area is to drill an exploratory well. This consists of digging into the Earth's crust to allow geologists to study the composition of the underground rock layers in detail. In addition to looking for natural gas and petroleum deposits by drilling an exploratory well, geologists also examine the drill cuttings and fluids to gain a better understanding of the geologic features of the area. Logging, explained below, is another tool used in developed as well as exploratory wells. Drilling an exploratory well is an expensive, time consuming effort. Therefore, exploratory wells are only drilled in areas where other data has indicated a high probability of petroleum formations. For more information on the process of drilling natural gas wells

Logging

Logging refers to performing tests during or after the drilling process to allow geologists and drill operators to monitor the progress of the well drilling and to gain a clearer picture of subsurface formations. There are many different types of logging, in fact; over 100 different logging tests can be performed, but essentially they consist of a variety of tests that illuminate the true composition and characteristics of the different layers of rock that the well passes through. Logging is also essential during the drilling process. Monitoring logs can ensure that the correct drilling equipment is used and that drilling is not continued if unfavorable conditions develop.

It is beyond the scope of this website to get into detail concerning the various types of logging tests that can be performed. Various types of tests include standard, electric, acoustic, radioactivity, density, induction, caliper, directional and nuclear logging, to name but a few. Two of the most prolific and often performed tests include standard logging and electric logging.

Standard logging consists of examining and recording the physical aspects of a well. For example, the drill cuttings (pieces of rock displaced by the drilling of the well) are all examined and recorded, allowing geologists to physically examine the subsurface rock. Also, core samples are taken by lifting a sample of underground rock intact to the surface, allowing the various layers of rock and their thickness to be examined. These cuttings and cores are often examined using powerful microscopes that can magnify the rock up to 2,000 times. This allows the geologist to examine the porosity and fluid content of the subsurface rock, and to gain a better understanding of the earth in which the well is being drilled.

Electric logging consists of lowering a device used to measure the electric resistance of the rock layers in the 'down hole' portion of the well. This is done by running an electric current through the rock formation and measuring the resistance that it encounters along its way. This gives geologists an idea of the fluid content and characteristics. A newer version of electric logging, called induction electric logging, provides much the same types of readings, but is more easily performed and provides data that is more easily interpreted.

An Example of Well Log Data

Source: U.S. Geological Survey

An example of the data obtained through various forms of logging is shown below. In this representation, the different columns indicate the results of different types of tests. The data is interpreted by an experienced geologist, geophysicist, or petroleum engineer, who is able to learn from what appear as 'squiggly' lines on the well data readout.

The drilling of an exploratory or developing well is the first contact that a geologist or petroleum engineer has with the actual contents of the subsurface geology. Logging, in its many forms, uses this opportunity to gain a fuller understanding of what actually lies beneath the surface. In addition to providing information specific to that particular well, vast archives of historical logs exist for geologists interested in the geologic features of a given or similar area.

To get more in-depth and technical information on well logging

Data Interpretation

There are many sources of data and information for the geologist and geophysicist to use in the exploration for hydrocarbons. However, this raw data alone would be useless without careful and methodical interpretation. Much like putting together a puzzle, the geophysicist uses all of the sources of data available to create a model, or educated guess, as to the structure of the layers of rock under the ground. Some techniques, including seismic exploration, lend themselves well to the construction of a hand- or computer-generated visual interpretation of an underground formation. Other sources of data, such as that obtained from core samples or logging, are taken into account by the geologist when determining the subsurface geological structures. Despite the amazing evolution of technology and exploration techniques, the only way of being sure that a petroleum or natural gas reservoir exists is to drill an exploratory well. Geologists and geophysicists can make their best guesses as to the location of reservoirs, but these are not infallible.

2-D Seismic Interpretation

Two-dimensional seismic imaging refers to geophysicists using the data collected from seismic exploration activities to develop a cross-sectional picture of the underground rock formations. The geophysicist interprets the seismic data obtained from the field, taking the vibration recordings of the seismograph and using them to develop a conceptual model of the composition and thickness of the various layers of rock underground. This process is normally used to map underground formations, and to make estimates based on the geologic structures to determine where it is likely that deposits may exist.

Another technique using basic seismic data is known as 'direct detection.' In the mid-1970s, it was discovered that white bands, called 'bright spots', often appeared on seismic recording strips. These white bands could indicate deposits of hydrocarbons. The nature of porous rock that contains natural gas could often result in reflecting stronger seismic reflections than normal, water-filled rock. Therefore, in these circumstances, the actual natural gas reservoir could be detected directly from the seismic data. However, this does not hold universally. Many of these 'bright spots' do not contain hydrocarbons, and many deposits of hydrocarbons are not indicated by white strips on the seismic data. Therefore, although adding a new technique of locating petroleum and natural gas reservoirs, direct detection is not a completely reliable method.

source : http://www.naturalgas.org/naturalgas/exploration.asp

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Casing drilling

In the countryside, in shallow water or at great depths – our engineers start drilling at very different locations. All sites have several things in common: boreholes begin with an average diameter of some 70 cm, are mostly drilled to depths of several kilometres, and get narrower the deeper they go down. At the bottom they are little more than 10 cm in diameter. But how is a borehole actually constructed?

The drill string with the bit at the bottom end is made up of individual pipes, around nine metres long, with special threaded ends known as tool joints. Pre-assembled stands made up of three pipes ("trebles") are stood upright in the derrick. For the fitters on a rig assembly, their work means removing the protective caps, oiling the threads, screwing on a stand and then tightening everything up. A great deal of manual work is involved before a bit finally reaches its target formation thousands of metres underground. And that is not all. When a bit becomes blunt or something goes wrong, the whole string has to be brought up to the surface and the necessary action taken before it can be returned to the borehole.

Once the bit has drilled through the first massive, load-bearing rock formations, we bring in the first anchor pipe – a strong steel pipe with a slightly smaller diameter than the borehole. Then we carefully fill the gap between the pipe and the walls of the borehole with cement. Once it has dried, the pipe is firmly anchored in the rock. This stable connection is crucial if the anchor pipe is to safely bear all the additional loads. Our laboratory specialists are closely involved in the development of these cements, which not only form an effective seal between the reservoir and the surface and between the various rock formations, but also protect freshwater aquifers and ensure that the aggressive brines found in the pores of the rocks do not corrode the pipes.

In view of the complex and laborious steps the drilling process involves, we want, above all, to prevent the borehole from collapsing once drilling has been completed. This is why steel casing is cemented into place at various places en route to the reservoir – particularly in difficult-to-drill rock formations. These so-called casing strings are made up of casing and a liner. When the casing is in place, the gap between the pipe and the borehole wall is again largely filled with cement. And once all this work has been completed, theoretically a well can go on stream.

However, before production commences, the well needs to be completed. A production string made up of joined-up pipes is lowered into the borehole. The pipes at the bottom end of the string are perforated with numerous holes or slits. This perforation allows the oil or gas to flow into the production string, which is not cemented in place but is embedded in a special kind of sand.

In casing drilling technology, which RWE Dea has used for several wells, there is no conventional drill string. For the drilling operation, the drilling crew use the casing string needed for production purposes. The drilling fluid (or mud) is pumped down through the casing, transports the cuttings to the surface, cools the bit and drives its motor. The mud flows through the annulus between the rock and the casing back up to the rig, where it is treated for re-use. While flowing back to the surface, the mud has an extremely positive lubricating effect – and that is the reason why longer casing strings can be used in these casing drilling operations. Another advantage of this technology is that casing can be continually run, which saves a great deal of time.

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Extended reach drilling

The rig in one place, the reservoir many kilometres away: wells often need to be drilled over huge distances to reach oil and gas deposits. Extremely long wells – extended reach drilling – are a demanding challenge for our personnel and the equipment they use.

We work our way to such a reservoir in much the same way as a doctor uses an endoscope to examine a patient's internal organs. Extended reach drilling is particularly suitable for producing oil or gas from an onshore site. RWE Dea operates Mittelplate Drilling and Production Island in the Wadden Sea National Park off the coast of Schleswig-Holstein in North Germany. From Mittelplate, the only drilling rig authorised to operate in this National Park, we can drill production wells of up to seven kilometres in length. To further protect the environment of this unique mud flats landscape, all future production wells will be drilled from an onshore site – technically speaking, a highly demanding undertaking. Two preconditions need to be met: the reservoir cannot be too far from the shore and the rock formations must not be heavily fissured. RWE Dea has already drilled 10 km wells and lengths of more than 15 km are being planned. We are relying on extended reach drilling to develop the reservoirs from onshore sites for our drilling operations in the Caspian Sea.

The distances involved with extended reach drilling mean that a drill string rotating through rock over thousands of metres is subject to particularly high torque and grinding forces. To avoid downtime or malfunction, friction needs to be minimised during the drilling operations therefore the drilling crew constantly flush the well with special drilling fluids (aka mud) and rotate the drill string. Without this rotating motion only about 8 km can be drilled but with rotation we have achieved 10 km. Also using this method, a distance of 12.345 km has been achieved and this is currently the longest well in the world located on the Russian island of Sachalin.

If you don't go forward, you go backwards – and that's why we are involved in projects that aim to optimise the drilling technology and may well achieve a new record in extended reach drilling. In Norway, we and a partner company are developing a new drilling method in which the fine particles of rock produced during drilling (so-called cuttings) are not removed from the borehole by traditional means (via the annulus) but through the inside of an innovative double drill string. This ensures that the annulus does not get bunged up and also enables better control on the pressure and volume flows.

There is also scope for improvement in the weight of the drill string. It needs to be robust, but at the same time as light as possible – the lighter and more voluminous it is, the lower the friction losses. We try to counteract such friction losses through the use of a heavyweight drilling fluid. This buoys up the drill string, which swims in the fluid and friction is reduced. To this end, we are also working on an aluminium drill string. In a separate research project we are developing a new carbon fibre-based plastic material that is both very strong yet lightweight. One day, it could well replace the steel drill string in use today.

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Safety measures

Safety first, before profitability: this imperative is enshrined the RWE Dea’s corporate mission statement, and it is complied with in the operation of our drilling and production sites on a daily basis. Any potential risks associated with drilling and production activities are countered with an extensive range of measures covering:

• the training and qualifications of our personnel
• risk and crisis management 
• the selection of contractors and materials
• supervision
• environmental aspects 
• conduct in the event of an incident

Training and qualifications of personnel

RWE Dea only employs drilling personnel with the appropriate qualifications. These employees continue to be trained in well control measures conforming to international standards in two-yearly intervals through the “International Well Control Forum”. Moreover, supervisory personnel and site engineers also undergo regular training to enable them to detect potential problems emerging during drilling and production immediately and respond with the appropriate measures. In the “SimWell” course, for example, a practice drilling rig generates inflows that must be detected, controlled and safely circulated out using the installed safety facilities. Seminars attended by both employees and contractors are designed to raise awareness of environmental protection and occupational safety issues.

Risk and crisis management

A management system designed to deal with crises allows us to assess potential risks and hazards associated with drilling activities and production facilities as accurately as possible, so that we are able to implement the appropriate preventative measures. Using this system, we can analyse a range of different risk situations and scenarios for their inherent crisis potential. These analyses provide answers regarding the likelihood of an event occurring, so that crisis priority ratings can be assigned and targeted preventive measures developed by the crisis management team. RWE Dea’s operating units all have their own catalogue of measures and emergency response plans, enabling them to mount a rapid and appropriate response to any conceivable events. To ensure that all these measures work perfectly not only in theory, practical fire-fighting and evacuation drills are carried out at regular intervals. RWE Dea employees have all undergone comprehensive preparations for dealing with emergencies in an operational setting.

Selection of contractors and materials

Safety issues are not limited to what happens on the drill rig. Quality, health, safety and environmental protection aspects are taken into account as early as during the preparation of the specifications for services provided by contractors and for materials. Technology, quality and risk factors play an important role in the selection of suppliers and are an integral part of tender evaluations. Our key strategic suppliers are assessed by means of a supplier management system; potential weakness are identified and appropriate measures for improvement are jointly stipulated.

Supervision

In the international environment in which RWE Dea operates, all mining activities are reviewed and approved by the relevant authorities. In some countries, there is a legal requirement that independent third parties review the submitted application and the design of wells and equipment before applications can be approved by the public authorities in question. Any changes to an already approved concept must be reported and explained in detail. However, the conditions and controls stipulated by government authorities are just one component in the supervisory process. In addition, anyone with responsibility for aspects of our projects must familiarise themselves with any approvals and conditions imposed by the authorities that impinge on their area of responsibility. The same applies to the supervisory staff of external companies. We further ensure continuous, professional-standard monitoring of all safety aspects, either by our own staff of by appropriately trained managerial staff working for our outside companies.

Environment

Protection of the environment is entrenched in the Corporate Mission Statement of RWE Dea as a high-priority policy objective. Our organisation and all our employees have made a commitment to act accordingly as they go about their work. We have a “zero incident” policy in relation to occupational and plant safety as well as for environmental protection. We can achieve this through targeted measures to eliminate incidents. This includes efforts to thoroughly investigate the causes of any incident or “near-miss” cases. By eliminating not only faults and incidents, but focusing closely above all on their causes, we can ensure a continual process of improvement.
The environmental studies carried out by us look at the dynamic interaction between exploration, drilling and production activities and the environment. The studies provide information about the effect our activities can have on the environment – from seismic surveys and the drilling of exploration wells right through to the extraction of natural gas and crude. They also indicate the type the environmental protection measures we need to develop and implement to ensure that there will be no long-term damage once operations have been completed.

Conduct in the event of an incident

All organisational units of RWE Dea have effective contingency plans for dealing with emergencies in place and are familiar with their operation. These plans cover all the necessary information, telephone numbers, flow charts and rules of conduct. No aspect of oil pollution control, fire fighting, alarm chain and emergency measures is neglected. These plans are actually “lived” in safety courses, drills and seminars conducted on a regular basis. Appropriate actions by personnel working in every position within the company are subject to constant monitoring. A system of alerts that operates round the clock is designed to convene the crisis management team in the case of an emergency.

source : http://www.rwe.com/

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Safety during drilling operations

Using leading-edge technologies, our aim is to prevent hydrocarbons from reaching the surface in an uncontrolled manner during drilling operations. We use a series of effective methods for preventing potential incidents or controlling and mitigating their impact. The safety technologies deployed during drilling operations encompass three key components:

• drilling mud
• the blow-out preventer
• cementing

Drilling mud

The first line of defence against the uncontrolled exit of oil or gas from a well is drilling mud, which is injected into the well in a closed circuit. The specific gravity of the drilling mud is adjusted based on detailed calculations that take into account the pore pressures that may be encountered in the rock formations to be drilled. The hydrostatic pressure produced in this way controls the formation pressures and prevents hydrocarbon leakage.

Blow-out preventer

Aside from the properly adjusted specific weight of the drilling mud, the so-called blow-out preventer is the most vital safety device. It is located directly at the wellhead and consists of several independently operating shutoff valves, each of a different design.

The well is shut off by means of a jaw-shaped slide valve and a ring-shaped cuff. Together they ensure that the drilling string in the well is enclosed in such a way that the well is completely sealed off in the event of an emergency. Should a complete shut-off become necessary, the shear jaws can be used to cut off the drilling string and shut off the well. High-pressure conduits mounted on the blow-out preventer allow fluids to be circulated in and out of the well even once it is shut off. The shut-off valves are connected to a hydraulic system through which each valve can be controlled individually.

The blow-out preventer can be operated manually or automatically. If it is located on the seafloor, it can also be operated by means of a Remote Operated Vessel (ROV) or by remote control using sound waves. The blow-out preventer is firmly connected to the well casing and is subjected to regular inspections and a range of function and pressure tests.

Cementing

A qualified cementing of the casing string also contributes to the safety of the borehole. Cement is used to stabilise and seal the individual casing sections. The cementing ensures a tear-proof connection to the surrounding loose rock that is impermeable to gas and fluids. This prevents the uncontrolled rise of hydrocarbons outside the casings as well as damage or corrosion. For this reason, cementing is always planned and executed in such a way that a permanent seal suitable for the prevailing reservoir conditions is created. The proper functioning of the seal is established using various measurement and monitoring methods.

source : http://www.rwe.com

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Drilling fluid types

There are several different types of drilling fluids, based on both their composition and use. The three key factors that drive decisions about the type of drilling fluid selected for a specific well are:

• Cost
• Technical performance
• Environmental impact.

Selecting the correct type of fluid for the specific conditions is an important part of successful drilling operations.

Classification of drilling fluids

World Oil’s annual classification of fluid systems[1] lists nine distinct categories of drilling fluids, including:

• Freshwater systems
• Saltwater systems
• Oil- or synthetic-based systems
• Pneumatic (air, mist, foam, gas) “fluid” systems

Three key factors usually determine the type of fluid selected for a specific well:

• Cost
• Technical performance
• Environmental impact

Water-based fluids (WBFs) are the most widely used systems, and are considered less expensive than oil-based fluids (OBFs) or synthetic-based fluids (SBFs). The OBFs and SBFs—also known as invert-emulsion systems—have an oil or synthetic base fluid as the continuous(or external) phase, and brine as the internal phase. Invert-emulsion systems have a higher cost per unit than most water-based fluids, so they often are selected when well conditions call for reliable shale inhibition and/or excellent lubricity. Water-based systems and invert-emulsion systems can be formulated to tolerate relatively high downhole temperatures. Pneumatic systems most commonly are implemented in areas where formation pressures are relatively low and the risk of lost circulation or formation damage is relatively high. The use of these systems requires specialized pressure-management equipment to help prevent the development of hazardous conditions when hydrocarbons are encountered.

Water-based fluids

Water-based fluids (WBFs) are used to drill approximately 80% of all wells.[2] The base fluid may be fresh water, seawater, brine, saturated brine, or a formate brine. The type of fluid selected depends on anticipated well conditions or on the specific interval of the well being drilled. For example, the surface interval typically is drilled with a low-density water- or seawater-based mud that contains few commercial additives. These systems incorporate natural clays in the course of the drilling operation. Some commercial bentonite or attapulgite also may be added to aid in fluid-loss control and to enhance hole-cleaning effectiveness. After surface casing is set and cemented, the operator often continues drilling with a WBF unless well conditions require displacing to an oil- or synthetic-based system.

WBFs fall into two broad categories: nondispersed and dispersed.

Nondispersed sytems

Simple gel-and-water systems used for tophole drilling are nondispersed, as are many of the advanced polymer systems that contain little or no bentonite. The natural clays that are incorporated into nondispersed systems are managed through dilution, encapsulation, and/or flocculation. A properly designed solids-control system can be used to remove fine solids from the mud system and help maintain drilling efficiency. The low-solids, nondispersed (LSND) polymer systems rely on high- and low-molecular-weight long-chain polymers to provide viscosity and fluid-loss control. Low-colloidal solids are encapsulated and flocculated for more efficient removal at the surface, which in turn decreases dilution requirements. Specially developed high-temperature polymers are available to help overcome gelation issues that might occur on high-pressure, high-temperature (HP/HT) wells.[3] With proper treatment, some LSND systems can be weighted to 17.0 to 18.0 ppg and run at 350°F and higher.

Dispersed systems

Dispersed systems are treated with chemical dispersants that are designed to deflocculate clay particles to allow improved rheology control in higher-density muds. Widely used dispersants include lignosulfonates, lignitic additives, and tannins. Dispersed systems typically require additions of caustic soda (NaOH) to maintain a pH level of 10.0 to 11.0. Dispersing a system can increase its tolerance for solids, making it possible to weight up to 20.0 ppg. The commonly used lignosulfonate system relies on relatively inexpensive additives and is familiar to most operator and rig personnel. Additional commonly used dispersed muds include lime and other cationic systems. A solids-laden dispersed system also can decrease the rate of penetration significantly and contribute to hole erosion.

Saltwater drilling fluids

Saltwater drilling fluids often are used for shale inhibition and for drilling salt formations. They also are known to inhibit the formation of ice-like hydrates that can accumulate around subsea wellheads and well-control equipment, blocking lines and impeding critical operations. Solids-free and low-solids systems can be formulated with high-density brines, such as:

• Calcium chloride
• Calcium bromide
• Zinc bromide
• Potassium and cesium formate

Polymer drilling fluids

Polymer drilling fluids are used to drill reactive formations where the requirement for shale inihbition is significant. Shale inhibitors frequently used are salts, glycols and amines, all of which are incompatible with the use of bentonite. These systems typically derive their viscosity profile from polymers such as xanthan gum and fluid loss control from starch or cellulose derivatives. Potassium chloride is an inexpensive and highly effective shale inhibitor which is widely used as the base brine for polymer drilling fluids in many parts of the world. Glycol and amine-based inhibitors can be added to further enhance the inhibitive properties of these fluids.

Drill-in fluids

Drilling into a pay zone with a conventional fluid can introduce a host of previously undefined risks, all of which diminish reservoir connectivity with the wellbore or reduce formation permeability. This is particularly true in horizontal wells, where the pay zone can be exposed to the drilling fluid over a long interval. Selecting the most suitable fluid system for drilling into the pay zone requires a thorough understanding of the reservoir. Using data generated by lab testing on core plugs from carefully selected pay zone cores, a reservoir-fluid-sensitivity study should be conducted to determine the morphological and mineralogical composition of the reservoir rock. Natural reservoir fluids should be analyzed to establish their chemical makeup. The degree of damage that could be caused by anticipated problems can be modeled, as can the effectiveness of possible solutions for mitigating the risks.

A drill-in fluid (DIF) is a clean fluid that is designed to cause little or no loss of the natural permeability of the pay zone, and to provide superior hole cleaning and easy cleanup. DIFs can be:

• Water-based
• Brine-based
• Oil-based
• Synthetic-based

In addition to being safe and economical for the application, a DIF should be compatible with the reservoir’s native fluids to avoid causing precipitation of salts or production of emulsions. A suitable nondamaging fluid should establish a filter cake on the face of the formation, but should not penetrate too far into the formation pore pattern. The fluid filtrate should inhibit or prevent swelling of reactive clay particles within the pore throats.

Formation damage commonly is caused by:

• Pay zone invasion and plugging by fine particles
• Formation clay swelling
• Commingling of incompatible fluids
• Movement of dislodged formation pore-filling particles
• Changes in reservoir-rock wettability
• Formation of emulsions or water blocks

Once a damage mechanism has diminished the permeability of a reservoir, it seldom is possible to restore the reservoir to its original condition.

Oil-based fluids

Oil-based systems were developed and introduced in the 1960s to help address several drilling problems:

• Formation clays that react, swell, or slough after exposure to WBFs
• Increasing downhole temperatures
• Contaminants
• Stuck pipe and torque and drag

Oil-based fluids (OBFs) in use today are formulated with diesel, mineral oil, or low-toxicity linear olefins and paraffins. The olefins and paraffins are often referred to as "synthetics" although some are derived from distillation of crude oil and some are chemically synthesised from smaller molecules. The electrical stability of the internal brine or water phase is monitored to help ensure that the strength of the emulsion is maintained at or near a predetermined value. The emulsion should be stable enough to incorporate additional water volume if a downhole water flow is encountered.

Barite is used to increase system density, and specially-treated organophilic bentonite is the primary viscosifier in most oil-based systems. The emulsified water phase also contributes to fluid viscosity. Organophilic lignitic, asphaltic and polymeric materials are added to help control HP/HT(High pressure/High temperature) fluid loss. Oil-wetting is essential for ensuring that particulate materials remain in suspension. The surfactants used for oil-wetting also can work as thinners. Oil-based systems usually contain lime to maintain an elevated pH, resist adverse effects of hydrogen sulfide (H2S) and carbon dioxide (CO2) gases, and enhance emulsion stability.

Shale inhibition is one of the key benefits of using an oil-based system. The high-salinity water phase helps to prevent shales from hydrating, swelling, and sloughing into the wellbore. Most conventional oil-based mud (OBM) systems are formulated with calcium chloride brine, which appears to offer the best inhibition properties for most shales.

The ratio of the oil percentage to the water percentage in the liquid phase of an oil-based system is called its oil/water ratio. Oil-based systems generally function well with an oil/water ratio in the range from 65/35 to 95/5, but the most commonly observed range is from 70/30 to 90/10.

The discharge of whole fluid or cuttings generated with OBFs is not permitted in most offshore-drilling areas. All such drilled cuttings and waste fluids are processed, and shipped to shore for disposal. Whereas many land wells continue to be drilled with diesel-based fluids, the development of synthetic-based fluids (SBFs) in the late 1980s provided new options to offshore operators who depend on the drilling performance of oil-based systems to help hold down overall drilling costs but require more environmentally-friendly fluids. In some areas of the world such as the North Sea, even these fluids are prohibited for offshore discharge.

Synthetic-based drilling fluids

Synthetic-based fluids were developed out of an increasing desire to reduce the environmental impact of offshore drilling operations, but without sacrificing the cost-effectiveness of oil-based systems.

Like traditional OBFs, SBFs can be used to:

• Maximize rate of penetrations (ROPs)
• Increase lubricity in directional and horizontal wells
• Minimize wellbore-stability problems, such as those caused by reactive shales

Field data gathered since the early 1990s confirm that SBFs provide exceptional drilling performance, easily equaling that of diesel- and mineral-oil-based fluids.

In many offshore areas, regulations that prohibit the discharge of cuttings drilled with OBFs do not apply to some of the synthetic-based systems. SBFs’ cost per barrel can be higher, but they have proved economical in many offshore applications for the same reasons that traditional OBFs have: fast penetration rates and less mud-related nonproductive time (NPT). SBFs that are formulated with linear alphaolefins (LAO) and isomerized olefins (IO) exhibit the lower kinematic viscosities that are required in response to the increasing importance of viscosity issues as operators move into deeper waters. Early ester-based systems exhibited high kinematic viscosity, a condition that is magnified in the cold temperatures encountered in deepwater risers. However, a shorter-chain-length (C8), low-viscosity ester that was developed in 2000 exhibits viscosity similar to or lower than that of the other base fluids, specifically the heavily used IO systems. Because of their high biodegradability and low toxicity, esters are universally recognized as the best base fluid for environmental performance.

By the end of 2001, deepwater wells were providing 59%; of the oil being produced in the Gulf of Mexico.[4] Until operators began drilling in these deepwater locations, where the pore pressure/fracture gradient (PP/FG) margin is very narrow and mile-long risers are not uncommon, the standard synthetic formulations provided satisfactory performance. However, the issues that arose because of deepwater drilling and changing environmental regulations prompted a closer examination of several seemingly essential additives.

When cold temperatures are encountered, conventional SBFs might develop undesirably high viscosities as a result of the organophilic clay and lignitic additives in the system. The introduction of SBFs formulated with zero or minimal additions of organophilic clay and lignitic products allowed rheological and fluid-loss properties to be controlled through the fluid-emulsion characteristics. The performance advantages of these systems include:

• High, flat gel strengths that break with minimal initiation pressure
• Significantly lower equivalent circulating densities (ECDs)
• Reduced mud losses while drilling, running casing, and cementing

All-oil fluids

Normally, the high-salinity water phase of an invert-emulsion fluid helps to stabilize reactive shale and prevent swelling. However, drilling fluids that are formulated with diesel- or synthetic-based oil and no water phase are used to drill long shale intervals where the salinity of the formation water is highly variable. By eliminating the water phase, the all-oil drilling fluid can preserve shale stability throughout the interval.

Pneumatic-drilling fluids

Compressed air or gas can be used in place of drilling fluid to circulate cuttings out of the wellbore. Pneumatic fluids fall into one of three categories:

• Air or gas only
• Aerated fluid
• Foam[5]

Pneumatic-drilling operations require specialized equipment to help ensure safe management of the cuttings and formation fluids that return to surface, as well as tanks, compressors, lines, and valves associated with the gas used for drilling or aerating the drilling fluid or foam.

Except when drilling through high-pressure hydrocarbon- or fluid-laden formations that demand a high-density fluid to prevent well-control issues, using pneumatic fluids offers several advantages[6]:

• Little or no formation damage
• Rapid evaluation of cuttings for the presence of hydrocarbons
• Prevention of lost circulation
• Significantly higher penetration rates in hard-rock formations

Specialty products

Drilling-fluid service companies provide a wide range of additives that are designed to prevent or mitigate costly well-construction delays. Examples of these products include:

• Lost-circulation materials (LCM) that help to prevent or stop downhole mud losses into weak or depleted formations.
• Spotting fluids that help to free stuck pipe.
• Lubricants for WBFs that ease torque and drag and facilitate drilling in high-angle environments.
• Protective chemicals (e.g., scale and corrosion inhibitors, biocides, and H2S scavengers) that prevent damage to tubulars and personnel.

Lost-circulation materials

Many types of LCM are available to address loss situations:

• Sized calcium carbonate
• Mica
• Fibrous material
• Cellophane
• Crushed walnut shells

The development of deformable graphitic materials that can continuously seal off fractures under changing pressure conditions has allowed operators to cure some types of losses more consistently. The application of these and similar materials to prevent or slow down the physical destabilisation of the wellbore has proved successful. Hydratable and rapid-set lost-circulation pills also are effective for curing severe and total losses. Some of these fast-acting pills can be mixed and pumped with standard rig equipment, while others require special mixing and pumping equipment.

Spotting fluids

Most spotting fluids are designed to penetrate and break up the wall cake around the drillstring. A soak period usually is required to achieve results. Spotting fluids typically are formulated with a base fluid and additives that can be incorporated into the active mud system with no adverse effects after the pipe is freed and/or circulation resumes.

Lubricants

Lubricants might contain hydrocarbon-based materials, or can be formulated specifically for use in areas where environmental regulations prohibit the use of an oil-based additive. Tiny glass or polymer beads also can be added to the drilling fluid to increase lubricity. Lubricants are designed to reduce friction in metal-to-metal contact, and to provide lubricity to the drillstring in the open hole, especially in deviated wells, where the drillstring is likely to have continuous contact with the wellbore.

Corrosion, inhibitors, biocides, and scavengers

Corrosion causes the majority of drillpipe loss and damages casing, mud pumps, bits, and downhole tools. As downhole temperatures increase, corrosion also increases at a corresponding rate, if the drillstring is not protected by chemical treatment. Abrasive materials in the drilling fluid can accelerate corrosion by scouring away protective films. Corrosion, typically, is caused by one or more factors that include:

• Exposure to oxygen, H2S, and/or CO2
• Bacterial activity in the drilling fluid
• High-temperature environments
• Contact with sulfur-containing materials

Drillstring coupons can be inserted between joints of drillpipe as the pipe is tripped in the hole. When the pipe next is tripped out of the hole, the coupon can be examined for signs of pitting and corrosion to determine whether the drillstring components are undergoing similar damage.

H2S and CO2 frequently are present in the same formation. Scavenger and inhibitor treatments should be designed to counteract both gases if an influx occurs because of underbalanced drilling conditions. Maintaining a high pH helps control H2S and CO2, and prevents bacteria from souring the drilling fluid. Bacteria also can be controlled using a microbiocide additive.

References

1. ↑ World Oil 2004 Drilling, Completion and Workover Fluids. 2004. World Oil 225 (6): F-1.
2. ↑ Oilfield Market Report 2004. Spears & Assoc. Inc., Tulsa, Oklahoma, www.spearsresearch.com.
3. ↑ Mason, W. and Gleason, D. 2003. System Designed for Deep, Hot Wells. American Oil and Gas Reporter 46(8): 70.
4. ↑ Deepwater Production Summary by Year, Gulf of Mexico Region, Offshore Information. Minerals Management Service, U.S. Dept. of the Interior, www.gomr.mms.gov/homepg/offshore/deepwatr/summary.asp.
5. ↑ Lyons, W.C., Guo, B., and Seidel, F. 2001. Air and Gas Drilling Manual. New York: McGraw-Hill.
6. ↑ Negrao, A.F., Lage, A.C.V.M., and Cunha, J.C. 1999. An Overview of Air/Gas/Foam Drilling in Brazil. SPE Drill & Compl 14 (2): 109-114. SPE-56865-PA. http://dx.doi.org/10.2118/56865-PA

source: http://petrowiki.org/Drilling_fluid_types

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