Reduced Tubing Wear with Coupling

The economic landscape of the oil and gas industry has shifted and, as a result, operators in U.S. shale plays are increasingly looking for ways to streamline their practices and boost profitability. Coming to grips with production costs is crucial in the $50/bbl environment, and every component used in production should be scrutinized to assess if changes and improvements can be made to reduce wastage, costs and time lost on the well.

For example, nearly all of the wells operating in U.S. shale fields require artificial lift, and nearly half of those wells experience failure as a result of couplings contacting the inner tube wall, which creates friction that leads to considerable wear and damage. These failures are both hazardous and costly, running into the tens of thousands of dollars per well per year. Across the industry workover costs account for hundreds of millions of dollars per year.

To come up with an efficient, more cost-effective solution for well workovers, Materion Corp. partnered with Hess Corp. to develop and field test stronger, more fatigue-resistant sucker rod couplings made of ToughMet 3 TS95 alloy.

Materion developed a new temper of its ToughMet 3 alloy specifically to address the challenges of coupling on tubing wear. This copper-nickel-tin spinodal alloy was originally engineered by Materion for use in drilling equipment. Offering high strength and low friction, this alloy demonstrates corrosion and corrosion-related stress cracking resistance in seawater, chlorides and sulfides.

With its combination of properties, this alloy resists mechanical wear, thread damage, corrosion and erosion. The couplings are non-galling, so they do not damage production tubing, and they retain their strength even at elevated temperatures.

Bakken-tested

Materion partnered with Hess, one of the largest producers in the Bakken, to qualify and pilot the ToughMet sucker rod couplings in deviated wells with higher than normal failure rates. Hess noted that the couplings more than tripled the mean time between failures associated with couplings made of alternative materials.

Encouraged by the results observed in the field tests, the company installed the couplings in more than 400 of its Bakken wells and now uses the couplings as part of its standard production practice.

Materion is expanding the deployment of its ToughMet couplings with additional operators in several different shale plays. Now about 20 operators are running the couplings in the Bakken and Permian and in the Elk Hills Field in California. To facilitate access to the couplings for operators, Materion is establishing distributors in each of these regions so that the couplings are available from local inventory.

Permian perspective

Discovery Natural Resources LLC is a private oil and gas company that operates more than 1,000 wells in the Permian Basin. To date, the company has used the ToughMet couplings in about 20 wells in the Permian and is seeing positive results.

Discovery owns some wells that were failing every 60 to 90 days, specifically due to rod-on-tubing wear as a result of extreme deviation. The company piloted the ToughMet couplings as a solution and as a result significantly increased the run time on those wells.

Discovery reported that its longest running well with these couplings is more than 385 days without a failure. The company has four additional wells with the couplings installed that are past the 300-day mark. In addition, Discovery has doubled or tripled its run times.

Discovery pulled the rods out of one of the ToughMet test wells after a pump failure and inspected the couplings after three months of the well running. It would typically see significant tubing or coupling wear after this period in the ground but saw that the original stencils from the manufacture were still visible on the coupling (see image above). There was minimal wear observed on the couplings. For Discovery that was an early indication that the couplings reduced rod-on-tubing wear.

Sucker rod pumping in long deviated unconventional wells is especially challenging because of side-loading of rods. Sucker rods can buckle due to forces acting in compression at the bottom of the rodstring on downstroke.

If rod side loads are calculated at more than 100 lb, Discovery considers running ToughMet couplings in that area to increase the run time on that particular well. The company reported that ToughMet is becoming increasingly well-established in its operations. Now that the test phase is completed, the company is using more ToughMet couplings.

By utilizing a sucker rod coupling that actively mitigates coupling-on-tubing wear, operators are helping reduce downtime and improve production efficiencies by eliminating the need for more frequent workovers.

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General Step and Procedure Oil Gas Drilling in Onshore

To find oil, you cannot simply punch a hole in the ground. Perhaps, this is what many people believe.

There are many complexities involving multiple service companies and two complete teams of crews. With so much happening (and with so many difficulties regarding scheduling, safety, and environmental practices) drilling for oil is not for the faint of heart.

This is a general 51 steps for drilling in the USA, for example. 

The following steps are necessary in order to produce oil or gas from a well:

1. 10-30 different service companies are required.
2. Each company working on a well must adhere to around-the-clock scheduling, safety and environmental practices.
3. Build a new road to access the rig location.
4. Clear the area for the new rig.
5. Build infrastructure for water and electricity around the rig site.
6. Dig an earthen pit to prevent soil or water table contamination.
7. Dig a pilot hole at the precise location marked by the survey crew.
8. Dig two other holes (the “mouse” hole and the “rat” hole) nearby to hold pieces of equipment and pipe during drilling.
9. A rig that can dig a 10,000 ft. well requires 50-75 people and 35-45 semi-trucks to move and assemble the rig.
10. Assembly of the rig takes around 3 and a half days.
11. A strict inspection of the rig must take place once built.
12. Operations of the rig go on 24/7, typically ceasing only one day each year for Christmas.
13. Two shifts of two complete crews must work the rig every day.
14. There are two stages of drilling: 1. running and cementing of cases and 2. drilling until the bit reaches the depth of the targeted zone.
15. Each drill bit typically lasts 4,500 – 6,500 feet of drilling.
16. Replacing the bit requires the removal of the entire string of drill pipe in a process called “tripping out”.
17. “Tripping out” takes several hours and requires crews to cool the bit and keep the soil and hole intact.
18. To help keep cuttings from plugging the hole, the mud must be sent through shakers to send the cuttings into a separated area.
19. Additional mug system equipment: de-sanders, de-silters and de-gassers, remove smaller particles and gas from the mud.
20. Clean mud is then recirculated back down into the hole.
21. The Blow-Out Preventer (or “BOP”) is installed on top of the casing head before drilling takes place.
22. The BOP must have high-pressure safetly valves designed to seal off the well and block any escaping gases or liquids from the hole beneath in order to prevent a blow-out from occuring.
23. Drilling must begin with a designated surface depth, usually around 50-100 feet below the water table.
24. Special care must be taken to prevent contamination of the water in the water table while drilling by isolating the water table and the wall with concrete and steel encasing.
25. New sections of pipe must be added to the string as the bit drills deeper.
26. When the hole reaches a designated depth, the derrickhands secrete fluid through the hole to condition it for logging.
27. A “logging tool” measures the depth and condition of the hole for the oil company.
28. The tool gives the information of whether or not the well can indeed produce oil or gas.
29. At this point, it must be determined whether the well is to be complete or plugged and abandoned.
30. If the well is designated as a producer, the crew must re-insert the pipe back into the hole to ensure the hole is still intact.
31. To test the hole, mud must be re-circulated.
32. Once everything tests positively, the drill pipe is removed.
33. At this point, the crew must insert the last string of production casing running the entire depth of the hole.
34. Then, the casing is cemented in the hole.
35. The production crew then brings in the work-over unit and rigs it up to prepare the hole for production.
36. The crew runs small diameter tubing into the hole as a conduit for oil or gas to flow through and up the well.
37. Next, the work over unit trips out of the hole and picks up a perforating gun.
38. The perforating gun is lowered into the hole to production depth using a thin metal cable called a “wireline”.
39. An electrical signal is sent down the wireline, firing the gun and igniting explosive charges.
40. These charges create holes through the cement encasing and formation connecting the well bore to the reservoir.
41. To stimulate the flow of hydrocarbons (or oil), sometimes it’s necessary to “frack” the well.
42. “Fracking” involves pumping air, sand and fluids under extreme pressure down the hole and out through the perforations.
43. This fractures or forces cracks into the formation.
44. The remaining particles will hold the cracks open, releasing the flow of oil or gas.
45. Monitoring the flow allows the crew to determine the best location for the “choke”.
46. The “choke” controls the flow of the oil or gas.
47. Once pressure is released, the hydrocarbons are allowed the escape through the fractured zone and flow into the well bore.
48. The oil or gas can now travel up the well casing string.
49. The well bore is isolated from the surrounding formations with casing and cement, preventing any contamination.
50. The final step is to install a pump jack or production well-head, or what’s called the “Christmas Tree”.
51. It’s the time to produce the well and plan for any future field development.

Watch the Video : 

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Solids Control Innovations To North American Shale Fields

While the last year has seen a ramping up of onshore drilling in shale fields across North America, it’s clear that “caution” still remains the watchword when it comes to drilling and production budgets.

Anadarko, ConocoPhillips and Hess already have announced reductions in 2017 E&P budgets, and in the words of Anadarko CEO R.A. Walker, “We sincerely believe the volatility of the current operating market requires financial discipline.”

Such volatility and the focus from shale operators and drilling contractors on financial discipline, reduced costs and increased efficiencies is shining the spotlight on a key sector of the drilling market—solids control.

Drilling fluids play a crucial role in drilling activity in shale fields, cooling and lubricating drillbits, carrying drill cuttings to the surface, controlling pressure at the bottom of the well and ensuring that the formation retains the properties defined for that well.

The effectiveness of such fluids is highly dependent on solids control and the ability to separate the mud from rock particles and low-gravity solids so that clean mud is recycled and circulated back into the drilling system. If there are too many solids in the mud, ROP is reduced, and torque, drag and abrasion are increased as well as potential lost circulation and production.

The more capable the drilling rigs and the better the solids control technologies, the greater the drilling efficiencies and levels of potential production.

Current technology limitations

Shale shakers separate drill cuttings by passing the muds through a shale screen with separation achieved by vibrations and high G-forces. But there are limitations to these devices.

First, there is the capex and opex required for the shale shakers—not a one-off cost but a drag on finances throughout operations due to the need for the shale screens to be continually replaced.

There also is more onsite equipment, personnel, and greater costs and HSE risk.

Also, there are the inefficiencies of the shale shaker-based process itself.

The drilled solids are often broken down into fine particles that are difficult to remove, leading to an increase in solids in the drilling fluid, a decline in drilling fluid efficiency and a negative impact on penetration rates and equivalent circulating density.

Another downside of vibrating-type shale shakers is higher volumes of mud being lost and more drilling waste generated. One industry guru working for a major operator once said that 15% of all the mud used per well is lost in some form or another via the shakers.

Viable alternative

It’s with these issues in mind that Cubility’s filter beltbased MudCube technology is proving an effective alternative to shale shakers in shale fields.

The MudCube is an enclosed vacuum-based system that eliminates the traditional process of shaking fl uid and solids. Instead, drilling fl uids are vacuumed through a rotating filter belt that uses high airfl ow to separate the cuttings from the fl uid.

The cleaned drilling fl uids are then returned to the active mud system, and the drilled solids are carried forward on the filter belt for disposal. As opposed to shakers, the MudCube processes 100% of the mud, immediately increasing performance.

The system also eliminates the need for multiple shaker panels, with the solids removal efficiency also ensuring that as much as 80% more mud is recovered than competing technologies, which is a huge benefit when multiplied by several onshore rigs.

The improved separation capabilities of the MudCube also lead to better quality drilling fluid, more drilling fluid recycled back to the mud tanks to be reused for drilling, less waste and improved drilling efficiencies with stable drilling fl uid properties and a decrease in nonproductive time.

There are also the financial benefits of avoiding screen replacements on a regular basis—filter belts need replacing but not at such fast rates.

In addition, the MudCube is a much more compact alternative to shale shakers. A typical three-deck shaker weighs about 3 metric tons compared to 1 ton for the MudCube.

Deployments across North America

The MudCube’s easy installation on drilling pads is ensuring that it can impact the bottom line almost immediately.

In 2016 Cubility partnered with EQT Corp., and the MudCubes were successfully deployed to an onshore fl uid rig that was drilling Marcellus wells in western Pennsylvania. Cuttings were easily lifted out of the wellbore, leading to immediately improved solids control and waste disposal.

The MudCube also has been successfully deployed for Murphy Oil in Canada, and the company is evaluating the service for possible use in the Eagle Ford Shale as well.

New Tech Solids Inc. and the MudCube delivered dry cuttings with Murphy Oil in Canada. (Source: Cubility)

Mending the broken value chain

Cubility also is looking to contractor partnerships and offering the MudCube as a rentable system to enable contractors to embrace the latest solids control innovations and address the broken value chain where operators drive down day rates, leaving contractors with little scope for new equipment.

To this end Cubility is partnering with Houston-based Stage 3 Separation in providing a modular, easy and inexpensive installation and operation of MudCube, a system specifically designed for onshore shale operations and that can be up and running in a matter of days as an integrated part of the rig design.

It’s through exclusive distribution partnerships such as this and also with Canadian-based New Tech Solids Inc. (a recent deployment is taking place with Shell via New Tech Solids) that the next few years is likely to see more and more MudCubes deployed across North American shale fields through these service providers.

In today’s tight but ultrafast land drilling market, any solids control solution must provide immediate “wins” in terms of reduced costs and increased efficiencies. Vacuum and filter belt-based enclosed solid control systems are achieving this. 

Read More → Solids Control Innovations To North American Shale Fields

Mobile Field Gas Conditioning Technology

The increasing popularity of dual-fuel engines for powering drilling and completions operations in the U.S. has led to a reduction of diesel fuel by up to 70%, according to Navigant Research. Not only does the use of field gas make refueling simpler, but it also reduces the number of fuel delivery trucks on the road as well as the need for “hot” fueling and flaring off unwanted gas. However, the biggest benefit of the use of field gas is the cost savings delivered in the form of reduced diesel fuel bills.

A traditional drilling rig, according to Navigant, can require upward of $2.5 million per year in diesel fuel costs. With potential savings like this, along with the other benefits created through its use, the adoption of dual-fuel systems as an alternative to diesel systems is increasing, especially in regard to their use in hydraulic fracturing spreads. Navigant reported that the annual dual-fuel engine revenue in the U.S. is expected to grow to more than $58.1 million by 2024.

For all of the benefits provided by dual fuel, there are a few challenges. For example, availability of existing natural gas gathering lines as well as the compatibility of the field gas Btu and the moisture content with the engine are the primary challenges that have helped create an environment for innovative solutions.

Challenge remover

Nacelle Solutions, a West Virginia-based provider of fueling solutions, developed a flexible mobile technology that is contained in a small footprint to condition all forms of field gas for use in engines during drilling and completions operations. This technology, known as Dwight, specifically addresses the issues of high Btu, high moisture content and more in an onsite trailerbased field gas conditioning system.

“We saw operators moving toward wanting to utilize natural gas to displace diesel fuel,” said Gov Graney, co-founder of Nacelle Solutions. “Well economics was one of many reasons for this shift. On a completions site it is not unrealistic for operations to burn through 15,000 gallons of diesel fuel in a day. So, at $2.50 per gallon, you’re looking at $37,500 per day spent on diesel fuel.”

The Dwight mobile field gas conditioning system processes rich source gas to power high-horsepower completions operations. (Source: Nacelle Solutions)

Engine technology has developed to the point where dual-fuel engines are readily available and have been proven to work well with the proper gas specifications, including Btu content below 1,100, according to Graney.

“The challenge for dual-fuel engines came from areas with high Btu and/or moisture content in the gas. To gain the benefits of utilizing field gas, this challenge needed a solution,” he said.

Seeing this as an opportunity to provide a service to an opening market, Nacelle Solutions was founded, and the Dwight mobile field gas conditioning system was developed.

“The Dwight enables a high-Btu source gas to be used as field gas by conditioning the gas stream to a specification that will maximize performance of the engine without damaging it,” he said.

Preplanning ensures that the mobile system is configured to work with the composition of the inlet gas source. The unit is connected to a single source of gas, typically tying directly into the customer’s gathering system. The completely self-contained system is built on a 15-m (48-ft) drop-deck trailer and can be deployed either onsite or on an adjacent pad, according to the company.

“After going through a series of regulators, knockout scrubbers, slug catchers and more, three streams of gas exit the system: one containing conditioned gas to power the equipment, an enriched stream that flows back into the customer’s pipeline and another containing free-standing produced fluids,” Graney said. “Everything stays in gaseous form with the system, [and] there are no natural gas liquids created, so therefore there is no need to store or handle natural gas liquids throughout the process. The system is typically brought in when the Btu content is over 1,100. We have a separate system for handling gas with Btu under 1,100.”

With an estimated 40% reduction in diesel fuel costs, according to the company, the No. 1 benefit is cost savings.

“Another benefit is the reduction in the carbon footprint on each location,” Graney added. “That is due to the reduction of fuel delivery trucks that are coming on the location burning diesel fuel as well as diesel being utilized in the engines there. From a safety standpoint it reduces the amount of hot fueling that is required on site.”

Case study

Pennsylvania-based Eclipse Resources worked with Nacelle early on in the development of the Dwight mobile field gas conditioning system. The system was deployed for operations at its Purple Hayes #1 superlateral well drilled in Ohio’s Utica Shale in 2016. According to Oleg Tolmachev, executive vice president and COO of Eclipse, the mobile field conditioning unit solved the challenge of using high-Btu gas and moisture-containing gas to where it becomes usable by dual-fuel engines.

“Specifically, Nacelle’s mobile equipment was the first of its kind at the time when we began utilizing it, and in fact we deployed the first prototype unit,” he said. “Cost savings and financial arrangements with Nacelle are proprietary information, but suffice it to say that these savings are significant, and we have been utilizing this technology in all of our completions operations.”

Read More → Mobile Field Gas Conditioning Technology

Oil Exploration With Gravity And Magnetic Geophysical Methods

Gravity and magnetic methods are an essential part of oil exploration. They do not replace seismic. Rather, they add to it. Despite being comparatively low-resolution, they have some very big advantages.

These geophysical methods passively measure natural variations in the earth’s gravity and magnetic fields over a map area and then try to relate these variations to geologic features in the subsurface. Lacking a controlled source, such surveys are usually environmentally unobjectionable.

At a comparatively low cost, airborne potential field surveys can provide coverage of large areas. Allowing quick regional coverage, even gravity surveys can now be recorded from an aircraft with airly high reliability.

In Canada, digital regional gravity and magnetic data are available at zero cost from federal government agencies. Local and detailed surveys are acquired by exploration companies.

Because many college programs tend to overemphasize seismic as almost the only geophysical tool for oil exploration, other methods are sometimes overlooked by explorationists and managers. Where useful gravity and magnetic data are disregarded, risk reduction is incomplete, and the results of exploration programs are less reliable.

What anomalies mean

The physical rock property that links gravity anomalies to rock composition is density. The rock property that links magnetic anomalies to rock composition is total magnetization. Thus, each potential-field method valuable provides its own picture of the subsurface.

Density is scalar, but magnetization is a vector total of a vast and commonly unpredictable variety of remanent and induced magnetizations. Unlike density, magnetization can depend on very slight variations in the occurrence and distribution of particular minerals, which may have little relation to the overall lithology.

A geophysical anomaly is the difference between the observed (measured) geophysical field value and the value that would be observed at the same location if the Earth were more uniform. Nonuniformities in the physical properties of rocks give rise to geophysical anomalies.

Being responsive to lateral variations in rock properties, gravity and magnetic methods are best suited for detecting steep discontinuities such as faults. Seismic methods, by contrast, are best for detecting vertical rock variations and low-angle discontinuities such as layer boundaries.

The gravity field is simple, unipolar and almost perfectly vertical. The geomagnetic field is complicated: It has two or more poles, and it is commonly strongly nonvertical. Besides, it changes all the time, necessitating frequent updates by government agencies.

Gravity lows (negative anomalies) occur where rocks in the subsurface have a comparatively low density, which reduces their downward gravitational pull. Where the rock density is relatively high, the gravitational pull is increased, and a gravity high (positive anomaly) occurs.

Magnetic anomalies are more complex because the magnetic field and rock magnetization are both complicated. With a nonvertical dipolar field, a single rock-made anomaly source can be deceptively associated with a pair of apparent anomalies: a high and a low side by side.

Gravity and magnetic surveys should be designed purposefully to resolve the specific kind of anomalies that are expected from geologic targets of interest in a particular study.

Gravity and magnetic surveys should be designed purposefully to resolve the specific kind of anomalies that are expected from geologic targets of interest in a particular study. If a survey is too tight, money is wasted on redundant coverage. If a survey is too sparse, the desirable anomalies are undersampled and not delineated sufficiently. The idea is to design the sparsest and smallest, hence cheapest, survey that would resolve all the expected desirable anomalies.

Examples of exploration use

In the platformal Phanerozoic Alberta and Williston basins, most big magnetic and gravity anomalies are associated with ductile structures and rock composition variations in the crystalline basement inherited from orogenic events in the Precambrian. Such ductile ancient structures were fairly seldom reactivated, and they had relatively little influence on the Phanerozoic basins above.

More important are the later brittle basement faults and fractures, whose offset can be as little as a few meters, sometimes below seismic resolution.

Such brittle faults had a variety of direct and indirect influences on many intervals in the Phanerozoic sedimentary cover. They are commonly associated with subtle gravity and magnetic lineaments, some of which cut across the regional pattern of major anomalies. To help delineate fault networks, researchers created a regional gravity and magnetic atlas of the southern and central part of the Alberta Basin.

A gravity or magnetic lineament can be a gradient zone, linear break in the anomaly pattern, straight anomaly or even an alignment of separate local anomalies. Long lineaments are more likely to be associated with faults than short ones, especially if they occur in swarms or are a part of a regional pattern.

The best data processing methods are simple and intuitive so that derivative maps and anomalies are easy to relate to their precursors in the raw data.

Gravity and magnetic data can be processed specifically to highlight subtle lineaments (Figure 1). Particularly useful processing methods tend to be first and second horizontal and vertical derivatives, third-order residuals, automatic gain control, total gradient (analytic signal) and shaded-relief maps (shadowgrams). Wavelength filtering has a major pitfall in that Gibbs ringing can produce lineament-like artifacts, so it is best avoided.

FIGURE 1. This regional horizontal-gradient magnetic map of central and southern Alberta shows selected lineaments highlighted as straight white lines (after Lyatsky et al., 2005). (Source: Lyatsky Geoscience Research & Consulting Ltd.)

To help identify faults, gravity and magnetic lineaments should be compared with topographic and drainage lineaments. Seismic data and geological studies can help to determine if suspected faults had an influence on any particular play interval.

In horst and graben basins such as the offshore Queen Charlotte Basin on the west coast of British Columbia, the first step is to examine geological information from the surrounding areas on land and from drillholes in the basin. The pattern of raised and lowered crustal blocks in and around the basin can be determined from geologic field mapping and from a combination of seismic and gravity data.

Magnetic data (Figure 2) in the Queen Charlotte Basin were used to further delineate the networks of local and regional faults. Seismic data in this basin suffer from an uneven maximum depth of signal penetration due to the presence of numerous volcanic stringers. On land and offshore magnetic data were instrumental in the delineation of extrusive and intrusive igneous rocks, which was crucial for understanding the patterns of organic maturation.

FIGURE 2. In this horizontal-gradient magnetic vector map of the Queen Charlotte Islands and Hecate Strait, British Columbia, the numbered heavy black arrows indicate magnetic lineaments. Light thin lines indicate the magnetic horizontal gradient, with length proportional to the gradient magnitude and pointing “downhill.” (Source: Lyatsky Geoscience Research & Consulting Ltd.)

Teaching of gravity and magnetic methods

The relatively low priority given to potential-field methods in many oil-oriented college programs impoverishes students and their employers. Where gravity and magnetics courses exist, too often they focus—with intimidatingly advanced mathematics—on the physics of potential fields at the expense of exploration applications, survey design and methods of geological interpretation.

Too many gravity and magnetics textbooks are also very mathematical (with a superb exception of Nettleton, 1971). Too little tends to be said about the relationships between anomalies and variations in rock composition, which is the key to geological interpretation.

Misleadingly, numerical inversions of potential fields data are sometimes presented as interpretations. However, mathematics is abstract. Interpretation is essentially geological, with geophysical data used to provide geological information.

When geologists, seismologists and potential fields experts are too narrowly specialized, they do not talk to each other enough. The result is commonly disregard of valuable gravity and magnetic information. Alternatively, interpretations are too numerical to be useful if geological considerations are ignored.

Gravity and magnetics experts in oil exploration should talk less in an echo chamber among themselves. They should learn to think more like their clients, who tend to be geologists and seismologists. Their work should be presented from first principles, with minimum mathematics and with maximum geological consideration. Only then can interdisciplinary walls be brought down and exploration managers can vividly see the essential practical utility of gravity and magnetic methods.

Source : www.epmag.com

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Fixed Platform for Oil-Gas drilling and Production

A fixed platform is a permanent structure attached to the bottom of the ocean, often for the purpose of offshore oil extraction. Most of the work space of this platform is lifted over the surface of the sea from rigid steel or concrete supports. This rules a fixed platform with mobile platforms floating on the surface of the sea and anchored to the bottom of the ocean by more or less flexible moorings. Fixed platforms are typically deployed in water less than 1,700 feet (520 meters) in depth, with deeper drilling activities requiring more complex mobile platforms.

The first productive offshore oil wells were drilled in Ohio Grand Lake St. Marys State Park in 1891, using fixed platforms set on wooden piles at the bottom of the lake. In 1947, the first fixed platform drilling rig located beyond the view of the earth was built in the Gulf of Mexico. Fixed platforms were the most common method of offshore drilling for most of the 20th century, although the first mobile drilling rigs were operating since the early 1930s. Due to their high stability, depth limitation, and high, modern cost Fixed platform drilling rigs are limited to long-run drilling operations in shallow waters.

Fixed platforms are connected directly to the bottom of the ocean by a structural support known as a jacket. The first jackets consisted of concrete foundation poles, while modern deep water jackets are the tough towers of steel tubular supports. The base of a coating can be several times larger than the top, and are often driven deep into the ocean floor mud for support. The jackets are either partially or entirely built to the ground and shipped to the deck's position on bargain tugboats. Once there, they dropped to the bottom of the ocean with the help of ROV, and pushed them into position using bats mounted on barges.

The bridges that form the work space of a platform are generally built on sheltered yards or bays. While the first barges were towed on barges, many modern bridges are built to float during transit. They got to the top of the waiting jacket using hydraulic jacks or barges, and are usually quite high above the floating line to avoid all but the biggest waves. Bridges can be up to 200 feet (60 meters) in diameter, and consist of several levels of work and living space.

If a fixed platform is near the shore, you can pump oil directly from the onshore drilling site of storage facilities through gas pipelines provided along the ocean floor. In the case of drilling operations far from the ground, the platform must include large reservoirs containing the oil as long as it can be transferred to a tanker. Storage tanks are often located below the floating line, where they serve as a ballast to help the platform withstand the power of waves and currents.

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What is Seismic Drilling

Seismic drilling, also known as drilling, is perforation conducted as part of a seismic survey of geological formation. In such studies, the team uses a series of controlled vibrations to generate a map of underground structures. This map can determine where deposited material is to be found and how accessible it will be drilling equipment. Seismic surveys are an important part of oil and gas, and are also used by researchers who want to map geological formations for scientific purposes.

In seismic drilling, a company uses a drill specially designed to dig a hole at the desired depth. Air and water cutters are both available for this purpose, and are often mounted on slides or mobile platforms. This allows the team to quickly move the drill between the positions, which may be critical on a large survey. The time it takes to establish a drilling platform and stabilize it can add considerably the overall time required for the survey, and as a result teams try to use mobile drills where it is possible to do so.

After sinking a hole, team members can mount explosives inside. These explosives cause ground vibrations when they go out. With the use of seismic equipment, the team can follow the movement and reflection of vibrations. This information can help build a map of underground features and formations. The seismic drilling team may include geologists, explosive experts, and other personnel with training in seismic surveys.

A permit is usually required for seismic drilling. The process can be disruptive and can cause problems for plants, animals, or residents in the region. Permission seekers must describe the area they want to work and what they will do there. While on the site, team members usually follow business protocols set to make the site as secure as possible. They also check waste material to keep the site clean and tidy.

If seismic drilling suggests that training is workable, the team can locate some locations for drilling wells. The company may sink some test wells to confirm the results before starting large-scale production on the site. This survey and exploration can be expensive, especially when companies believe that not all land sites will produce usable deposits. Some sites may not have any useful material, while other deposits may be visible on a seismic survey, but essentially unavailable due to their depth or configuration.

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Fracking, thousands of spills and accidents in US oil and gas wells

Spills of polluted fluids and chemicals from 16% of unconventional hydrocarbon wells

According to the study of "Unconventional Oil and Gas Spills: Risks, Mitigation Priorities, and State Reporting Requirements" published by Environmental Science & Technology by a team of US researchers led by Laureen Patterson of the Harvard Law School's Environmental Policy Initiative, the situation of the pollution generated by the USA fracking wells is serious: every year, from 2 to 16% of oil and gas wells exploited by the fracking technique in Colorado, New Mexico, North Dakota and Pennsylvania there have been spills of hydrocarbons, water filled with chemicals, fluids of hydraulic fracturing and other substances. The largest spillage tested by the study resulted in the leak of 100,000 liters of polluting liquids.

The study dealt with unconventional oil and gas spills in 31,481 wells operated by fracking technique in the 4 US states between 2005 and 2014, identifying 6,648 spills over the past 10 years. In all states, the first three years of a well's life, during drilling and hydraulic fracturing, have had the highest production volumes but also the highest risk of spillage. A significant part of the spills (from 26% in Colorado to 53% in North Dakota) occur in wells that have suffered more than one spill, "Which suggests that wells in which spillages have already occurred deserve more attention," they say researchers.

Figures that worsen many of the previous study, "Environmental Impact Assessment of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources" of the Environmental Protection Agency (EPA) on fracking in 8 US states between 2006 and 2012, which had concluded that there were 457 spills.

Patterson, interviewed by BBC News, explains why this strong difference: "The EPA has only looked at spills during the same process of hydraulic fracturing, which take place only in a period ranging from a few days to a few weeks. We have investigated spills in unconventional wells from the time of perforation throughout the production, which could last decades. "

In North Dakota, there were 4.453 accidents 

recorded

 , much more than in Pennsylvania, Colorado and New Mexico, and this can be explained with the different types of reporting. In North Dakota there must be reported any spill over 42 gallons, while in Colorado and New Mexico starts from 210 gallons.

Most of the spills occur during the first three years of wells activity and about 50% of spills occur from the pipelines for the transport of polluted fluids.

"The causes are quite different," says Patterson. "Equipment failures are the major factor, loading and unloading of trucks with material is a far more common human error than in other places."

. Researchers are convinced that "making state data on spills more consistent and accessible could provide stakeholders with important information on where to target efforts to identify and prevent 

future

 losses. However, reporting obligations differ between states, which requires considerable effort to make the data usable in order to be able to analyze them. "

Another author of the study, Kate Konschnik, also of the Harvard Law School, concludes: "Analysis like this is really important to defining and reducing the risks for water supply and human health. Writing state regulations for reporting these factors in mind is crucial to ensuring that correct data is available in the industry, the states and the research community, and in an accessible form. "

Read More → Fracking, thousands of spills and accidents in US oil and gas wells

17.6 million Americans live near oil and gas wells and fracking

Those who live within 1 Km from active wells are more at risk of cardiac and neurological problems, cancer and malformation at birth

Physicians, Scientists and Engineers (Why) for Healthy Energy is a non-profit research institute that provides scientific and technical information based on the health, environmental and climatic impacts of energy production and use and is now published on Environmental Perspectives Health  the study "Towards Consistent Methodology to Quantify Populations in Proximity in Oil and Gas Development: A National Spatial Analysis and Review of Environmental and Climate Dimensions of Energy Production and Use," which shows that "approximately 17.6 million Americans live within a kilometer of an active oil or gas well ". The study, conducted with researchers at the California-Berkley University and Havey Mudd Collegs, is the first US census on the number of people living near petroleum and gas production sites, both traditional and fracking wells .

The Why recall that previous studies "have found that active oil and gas production degrades the quality of air, surface water and groundwater; Contaminate soil and increase exposure to noise and light pollution. According to separate studies, when people live within one kilometer of these activities, they have a greater risk of being hospitalized for numerous medical problems, including heart and neurological problems, tumors, and increased incidence and severity of asthma. Neighborhood proximity to these activities has also been associated with birth problems, including premature birth, lower birth weight, neural tube defects, and congenital heart defects.

Yet so far, only a few studies have been published to quantify populations living near petroleum and gas stations and these studies did not link pollutant emissions to certain types of oil and gas production activities.

The study's main author, Eliza Czolowski, explains, "Our study was designed specifically to determine how many Americans saw increased health risks from potential exposure to pollutants emitted by petroleum and gas activities."

In addition to computing the total population of the Usa exposed, researchers analyzed exposure in the various US states by highlighting those with particularly high percentages of population living close to active wells. West Virginia was the most risky state, with 50% of residents living near an active oil or gas well. Right after Oklahoma, it's 47%. La Czolowski. It points out that "When a member on two of a population is potentially exposed to a health risk, this becomes a concern for public health."

Nearly a quarter of Ohioans - 24% - live alongside active wells. MA is the Texas true to most people at risk: 4.5 million. Near live ponds they live 1.4 million children up to 5 years old, a subgroup very vulnerable to environmental exposures

The researchers examined both hydraulic fracturing techniques (fracking) and traditional wells, and Czolowski noted that "Despite the differences in conventional and non-conventional oil production techniques, the health risks can be very similar. Many atmospheric pollutants, including benzene, formaldehyde and particulate matter, are emitted from both conventional and non-conventional activities because they are co-produced with oil and gas, not specifically because a well is fractured hydraulically. Also the emissions of atmospheric pollutants from associated activities, such as drilling wells and truck traffic, are not specific to hydraulic fracturing. "

The researchers point out that some of the data they requested were not available and therefore encourage further studies that follow similarly stringent methodologies, focusing in particular on public health, and taking into ACCOUNT variables excluded from their study, such as population density and activities.

The study concludes that "Given the large number of individuals and the large percentage of populations potentially exposed to pollutants emitted by petroleum and gas activities, protection standards and policies should be considered. Health protection policies may include minimum distances between these activities and places where they live, play and study people, as well as a widespread deployment of the best available technologies to reduce air pollution. "

Read More → 17.6 million Americans live near oil and gas wells and fracking

Purpose of Barite or Baryte

In oil and gas drilling

Worldwide, 69–77% of baryte (barite) is used as a weighting agent for drilling fluids in oil and gas exploration to suppress high formation pressures and prevent blowouts. As a well is drilled, the bit passes through various formations, each with different characteristics. The deeper the hole, the more baryte (barite) is needed as a percentage of the total mud mix. An additional benefit of baryte (barite) is that it is non-magnetic and thus does not interfere with magnetic measurements taken in the borehole, either during logging-while-drilling or in separate drill hole logging. Baryte (barite) used for drilling petroleum wells can be black, blue, brown or gray depending on the ore body. The baryte (barite) is finely ground so that at least 97% of the material, by weight, can pass through a 200-mesh (75 μm) screen, and no more than 30%, by weight, can be less than 6 μm diameter. The ground baryte (barite) also must be dense enough so that its specific gravity is 4.2 or greater, soft enough to not damage the bearings of a tricone drill bit, chemically inert, and containing no more than 250 milligrams per kilogram of soluble alkaline salts.[7] In August 2010 API (American Petroleum Institute) published specifications to modify the 4.2 drilling grade standards for baryte (barite) to include 4.1 SG materials.

In oxygen and sulfur isotopic analysis

In the deep ocean, away from continental sources of sediment, pelagic baryte (barite) precipitates and forms a significant amount of the sediments. Since baryte (barite) has oxygen, systematics in the δ18O of these sediments have been used to help constrain paleotemperatures for oceanic crust.

The variations in sulfur isotopes (34S/32S) are being examined in evaporite minerals containing sulfur (ex, baryte (barite)) and carbonate associated sulfates (CAS) to determine past seawater sulfur concentrations which can help identify specific depositonal periods such as anoxic or oxic conditions. The use of sulfur isotope reconstruction is often paired with oxygen when a molecule contains both elements.

Other uses

Baryte (Barite) is used in added-value applications which include filler in paint and plastics, sound reduction in engine compartments, coat of automobile finishes for smoothness and corrosion resistance, friction products for automobiles and trucks, radiation-shielding cement, glass ceramics and medical applications (for example, a barium meal before a contrast CAT scan). Baryte (barite) is supplied in a variety of forms and the price depends on the amount of processing; filler applications commanding higher prices following intense physical processing by grinding and micronising, and there are further premiums for whiteness and brightness and color.It is also used to produce other barium chemicals, notably barium carbonate which is used for the manufacture of LED glass for television and computer screens (historically in cathode ray tubes); and for dielectrics.

Historically baryte (barite) was used for the production of barium hydroxide for sugar refining, and as a white pigment for textiles, paper, and paint

Although baryte (barite) contains a "heavy" metal (barium), it is not a toxic chemical because of its extreme insolubility.

It is also sometimes used as gemstone.

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Oil Exploration

Crude oil is usually located deep below the earth's surface, without any visible traces of being present.

In the early years of the oil industry, one could easily find small amounts of oil in the vicinity of the oil urinating drilling. "Oil Lakes" are small amounts of oil that come up on the surface or in water.

However, a well drilling is very expensive; Therefore, alternative methods have been sought in order to locate oil. Today, geologists determined using a range of techniques where oil could be found. They make use of include seismic and visual observation techniques to determine the geological formations could contain oil.

• Seismic surveys

this case a small amount of underground explosive is detonated. In addition, to be sensitive instruments used which register the shock waves moving across the ground and which are reflected by rock walls. On the basis of the speed and direction of the waves geologists can identify the type of rock formations, and to detect the types of which are known to oil or hydrocarbons (such as gas) may contain.

• Vibro-seismic survey

, with special vibrating trucks are used, which is a controlled signal to submit the bottom. Although this method is more complicated, it is often used in places where explosives can not be used for practical reasons.

• Geophysical research

, this method is used to measure the thickness of sediment and in order to map out the shape of the structures within the sediment. In this way, often underground structures could be located in the last 30 years where oil had gathered.

• Research based on aerial photographs

on the basis of aerial photos, maps can be established in which the main geological properties are shown of an area. The photos are also used to determine oil field pipelines and infrastructure very closely. This information is of great value for planning seismic surveys and other projects.

• Surface Research

Here, specific localized areas on the ground and it is determined their height. One of the tools used therewith, is a theodolite, which is equipped with a telescope that measurement angles horizontally and vertically.

• Gravity investigation

In this method, there is used a highly sensitive gravimeter, which is analyzed to gravity variations. These variations may indeed indicate hidden geological structures. The study is usually performed in an early stage of exploration. The researchers thereby identify areas that may be potentially interesting. At these zones is then carried out, a more detailed seismic survey.

Drilling for oil

When certain areas of potential interest are labeled, are drills used to dig wells. Seismic research shows that the best places to look for oil. In this way, the risk of finding dry wells ( "dry hole") is limited. They contain no oil.

A drill is guided straight into the ground. If the rig can not be drawn directly on the surface, it is placed next to it and is drilled at an angle. The horizontal drilling technology is used to drill into the portion of the source which horizontally through the oil (the "output section") passes along the path from the oil reservoir.

Oil Transport

Crude oil is transported by pipeline from the drilling rig to tank farms. Since the oil is stored in huge tanks. The crude oil is then transported by pipeline to a local refinery or an oil tanker to an overseas refinery.

Read More → Oil Exploration

Shale Gas

What is shale gas? If you regularly read the newspaper, watching the news or visit news websites, you may have heard of the term "shale gas". This term is more and more often in the news and politics is increasingly concerned with the gas. But what this gas is and where this gas in the Netherlands? More on this subject, refer to this article.

Shale Gas: a fossil fuel

Shale is a fossil fuel that occurs locally in the so-called oil shale. Oil shale is called shale, a rock that can be found underground. Many compare with shale gas, but shale gas is a very different fossil fuels. This is because these fossil fuels not call in connected or prevents fields, as is the case with natural gas, but rather occurs in porous rock beneath sealing layers. So here's shale gas trapped in tiny pores, making it very difficult to win this fuel.

Shale gas and natural gas: the main difference

Although shale gas and alike used as the fossil fuels above the ground, under the ground is a clear difference between the two gases. Thus, the drilling of natural gas a completely different process from drilling shale gas, because gas bubbles in contiguous or prevents fields and can be easily drilled. In shale gas, this is not the case, through which the gas with thousands of small drilling in a variety of directions out of the ground needs to be achieved. In short, natural gas is easy to pick up from the ground, but the extraction of shale gas is a complex and time consuming.

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9 Distinct Mud Systems

For mud to manage its many tasks, a broad range of different fluid systems have been developed. 9 distinct mud systems are defined here. 

The first seven are water-based, while the eighth is oil-based. The ninth category is a specialized one in which air or gas is the continuous fluid. 

The 9 categories are:

1. Non dispersed. These may consist of spud muds, natural muds and other lightly treated systemsgenerally used for shallow wells or top-hole drilling.

2. Dispersed. At greater depths or where hole-conditions may be problematic, muds are often dispersed, typically by means of lignosulphonates or other deflocculants. These and similar products are also effective filtrate reducers.

3. Calcium treated. Divalent cations such as calcium and magnesium, when added to a mud, inhibit the swelling of formation clays and shale, and are therefore added to control sloughing shale, hole enlargement and to prevent formation damage. Hydrated lime, gypsum (calcium sulphate) and calcium chloride are principal ingredients of calcium systems. Gyp systems (note: Gyp = gypsum) usually have a pH of 9.5 to 10.5 and an excess gyp concentration of 2 to 4 lb/ bbl; Lime systems have an excess lime concentration of 1 to 15 lb/bbl and a pH of 11.5 to 12.0.

4. Polymer. Muds incorporating long-chain, high-molecular-weight chemicals are effective in increasing viscosity, flocculating muds, reducing filtrate loss and stabilizing the formation. Various types of polymers are available for this purpose, including Bentonite extenders. Bio polymers and cross-linked polymers are also used and have good shear-thinning properties at low concentrations.

5. Low solids. This includes systems in which the amount and type of solids are controlled. Total solids should not range higher than about 6% to 10% by volume (and clay < 3% by volume). One primary advantage of low-solids systems is that they significantly improve the rate of penetration.

6. Saturated salt. Include several groups: Saturated salt systems have a chloride ion concentration of 189 000 ppm. Saltwater systems have a chloride content from 6 000 to 189 000 ppm, and at its lower level are usually referred to as brackish or seawater systems.

7. Workover. Completion and workover fluids are specialized systems designed to minimize formation damage, and be compatible with acidizing and fracturing operations (acid soluble) and capable of inhibiting swelling clays that reduce formation permeability. Density is obtained  through dissolved salt to avoid long term settling.

8. Oil/synthetic. Oil-based fluids are used for high temperature wells, deviated holes and wells where pipe sticking and hole stabilization is a problem.

 They consist of two types of systems:

1) Invert emulsion muds are water-in-oil fluids and have water as the dispersed phase and oil as the continuous phase. They may contain up to 50% water in the liquid phase. Emulsifier (commonly fatty acids amine derivatives, high-molecular-weight soaps), and water concentrations are varied to control rheological and electrical stability;

2) Synthetic fluids are designed to duplicate the performance of oil-based muds, without the environmental hazards. Primary types of synthetic fluids are esters, poly alpha olefins and food grade paraffin. They are environmentally friendly, can be discharged offshore and are non-sheening and biodegradable.

9. Air, mist, foam and gas. Four basic operations are included in this specialized category according

to the IADC. These include:

1) Dry air drilling, which involves injecting dry air or gas into the wellbore at rates capable of achieving annular velocities that will remove cuttings;

2) Mist drilling involves injecting a foaming agent into the air stream, which mixes with produced water and lifts drill cuttings;

3) Stable foam uses chemical detergents and polymers and a foam generator to carry cuttings in fast-moving air stream;

4) Aerated fluids rely on mud with injected air (which reduces the hydrostatic head) to remove drilled solids from the wellbore.

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Directional Drilling

A drilling technique in which a well is bored to multiple angles. Directional drilling refers more often for the non-vertical angle drilling, including horizontally. It is used both to recover oil and natural gas underground, and is useful in situations where the shape of the tank is abnormal. It is also used to adjust pressure created by the gas in mines (degassing).

As a technique, directional drilling allows oil and gas operators to approach a potentially productive zone, without the need of a well to be drilled directly above that area. A central site can serve holes that reach more and more to non-vertical angles positions. This reduces the number of facilities and which must be constructed and maintained. With no need to build new wells may also lead to the exploration of smaller fields that would otherwise be uneconomical.

Early involved directional drilling tip of the tip with a different vertical angle, resulting in a straight line away from the well. The modern drilling techniques allow the use of tips that can bend; allow engineers to adjust the direction of the well is drilled to a certain extent. This can be accomplished through the use of hydraulic jets

Directional drilling is used in the development of mines, in order to reduce the risk of potentially dangerous gas breakages. In-mine drilling techniques allow companies to create holes in advance of my face.

While the basic concepts of directional drilling date back to the 19th century, has become a popular technique such as computer technology has become more common. The toe angle used for bored shaft can be regulated by a computer using GPS signals to pinpoint the location of an oil and gas field. Engineers create the 3D field models to determine the best location for good, and the best approach to the hole to follow.

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What is Drilling Mud

Fluid used in the drilling of wells. Drilling mud, also referred to as drilling fluid is one of drillingknowledge, is used to clear the hole of debris created during the drilling process, to cool the tip, and maintain the pressurized hole. The composition of the drilling mud used in the drilling process depends on the type of hole being drilled and the material to be bore. 

Drilling muds have been used to improve drilling operations for most of modern history. The water was used to smooth the surface material and remove scraps when they were drilled groundwater wells. contemporary drilling activities are much more sophisticated, and wells can reach miles below the surface in order to reach oil and natural gas.

The type of drilling mud used depends on the material drilled through, the technical requirements of the mud performance (viscosity and speed), cost and regulations. One of the primary functions of the drilling mud is to remove the shavings created by the drill hole. Because the wells are so deep it is impossible to remove the debris on the bottom without the use of some form of liquid. specialized Liquids are often used because they have high speed and viscosity, which allows them to move more easily when a drill both materials is in operation and to keep cutting suspended in the liquid when the drill is stopped.

The use of drilling mud, particularly specialized sludge using potentially hazardous chemicals is regulated. Regulations are used to ensure that the waste material is kept away from ground water, rivers and lakes, where pollution could cause the water to be safe and unusable for the public. Used drilling mud and sediment created during the drilling process can be used as pool treatments pumping in large pools.

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What Mud Fluid in drilling for ?

The drilling mud are primarily for:

1. to lubricate and cool the drill drilling that would otherwise warming, for the friction with the rock , quickly arrive at break.
2. Pipe on the surface of earth and rock fragments (commonly known by the English technical term for cutting ) produced by the action of the chisel.
3. Exercise a counter pressure hydrostatic hole at the bottom and along its walls discoveries (ie not tubate) to contain the leakage of the fluid layer and to avoid the risk of kick or in more severe cases the real eruption of the well.
4. Supporting walls of the hole (thanks to the pressure exerted by the hydrostatic load), in order to prevent landslides and loss of the punched hole. This feature is said that the mud must do "panel" that must practically "plaster" the walls of the well.
5. The most important properties of the drilling mud must be the "thixotropy", namely the characteristic that, at the time that the circulation in the pit stops, the sludge to be gelled fluid holding imprisoned in suspension the cutting resulting from the drilling. Otherwise these debris, stopping the circulation of the fluid, would fall to the bottom hole imprisoning the chisel and the "battery terminal part" drilling.

In the oil exploration monitoring geological of drilling muds, by analyzing the microscope of fragments of rock it allows to recognize the stratigraphy of the perforated rocky succession and provides the first indications of the characteristics petrophysical properties of the reservoir . 

Furthermore, the analysis by means of gas chromatographs , of the fluids contained in the outgoing mud from the well, provides important clues for the detection and recognition of mineralized levels to hydrocarbons.

In some cases similar muds are used temporarily to support the walls of trenches or over works of excavation of civil engineering within loose soil, prior to the implementation of their final completion.

Read More → What Mud Fluid in drilling for ?