The challenge to Drill the depth of the New Offshore Wells

About 80 kilometers from the coast, 1,500 meters below the water surface. The "numbers" of Macondo make an impression: just ten years ago the idea of ​​extracting oil on the high seas, at such high depths, was simply science fiction. And yet, faced with the greatest ecological disaster in the history of the oil industry, there is a comment that recurs with particular frequency among the experts: "BP was not dealing with a difficult well".

Over the course of a few years, the progress of offshore technologies has been so great that it has allowed companies to achieve the limits of the impossible, in front of which Macondo seems almost an amateur exercise. The Deepwater Horizon itself, the platform exploded on April 20, had just broken the submarine drilling record, identifying - again on behalf of BP and always in the Gulf of Mexico - the Tiber field, 10.6 km above sea level, of which over 9 under the backdrop.

There were 33 other offshore installations engaged in exploring the seabed at depths equal to or greater than those of Macondo in the United States. After the Macondo incident, the White House ordered that everyone stay for six months, waiting. of a crackdown on security conditions. The overall number of drills in the Gulf of Mexico, however, is much higher: according to the statistics of Rigzone, in April there were 243, of which about half were in use (in the world they were 578). As for the number of wells, the bottoms in front of Texas and Louisiana are literally studded with holes: it is estimated that there are about 3,500, dug with increasing frenzy as the search for crude oil on the mainland became more difficult, due to the decline of the most "at hand" fields and the spread of so-called resource nationalism. Technology has made it possible to make a virtue of necessity, with progress that in recent years has undergone a truly dizzying acceleration.

Oil was searched for the first time in water in 1938, at a depth of just 4 meters, with a few swimming strokes from Louisiana. The first really "offshore" well, 17 km off the same state, dates back to 1947: the platform was no bigger than a tennis court (the Deepwater Horizon had the size of a couple of football fields) and the crude was transported to land with barges taken by the Navy at the end of the Second World War.

It had to wait until the 1980s before Royal Dutch Shell managed to break the 1,000 foot deep (304.8 meter) threshold and up to 2000 to get to Macondo's 1.5 kilometer, with the Hoover Diana made by Saipem for ExxonMobil. Perdido - inaugurated last March 31 by Shell and capable of producing up to 100 thousand barrels of crude oil and 50 thousand cubic meters of gas per day - sinks its drills into the water for 3 km, more or less like five stacked Empire State Buildings.

But the real breakthrough in the offense is not only linked to the creation of increasingly powerful and sophisticated platforms, but to the new technologies for detecting the deposits, which allow to probe the depths, reconstructing images with three or even four dimensions of the potential deposits of hydrocarbons. This is how great discoveries have been made like that of Tupi, off the coast of Brazil, or Jubilee in the waters of Ghana. Discoveries that represent the future of oil. 

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New Platforms Design Withstand North Sea Conditions

The pressure to reduce the cost of new developments has never been greater for North Sea operators. The combination of low oil prices, decreased North Sea development opportunities and increased competition from the U.S. shale industry means the industry is being forced to adapt to new ideas.

One development concept that is starting to gain traction is the use of low-cost wellhead platforms for the development of small satellite fields. These are typically newly discovered fields close to an established host platform, which can provide control and power and also carry out fluid processing. Although wellhead platforms have long been a favorite in the shallow waters of the southern North Sea, up until now the preferred option for the development of satellite fields in deeper water has been to use a subsea manifold with a tieback to the host facility. Subsea manifolds are tried, tested and trusted, but WorleyParsons has carried out several studies showing that subsea manifolds don’t necessarily provide the best value solution for a multiple well development. The difficulties and additional costs associated with maintenance and future well intervention operations can all contribute to increased costs over the lifetime of a project.

WorleyParsons has accumulated a reference list of more than 500 installations that are currently operating throughout the world, and its team has combined its experience with ideas borrowed from the shale industry—where standardization and modularization of equipment is the key to low-cost field development. The company has come up with a new concept in wellhead platforms suitable for installation in deeper water and able to withstand North Sea conditions.

The new design uses piled foundations, can be deployed in water depths of up to 120 m (394 ft) and provides space for a maximum of 12 well slots. No accommodation has been provided for personnel, who will gain access for four monthly maintenance visits by vessels equipped with a “walk-to-work” gangway. The platform design includes a 5-tonne crane and sufficient deck space to allow full access for future well intervention. WorleyParsons also has designed the new platform for construction in its covered yard near Stavanger, Norway, with one flat side to permit installation by either barge launch or jackup platform to widen the choice of installation contractor.

The platform is designed with a “design once, build many” approach to capture economies of scale and efficiencies more closely associated with a production line than a North Sea construction yard. The design borrows from the philosophies that WorleyParsons has previously followed in the Persian Gulf and Gulf of Thailand and uses a minimum number of different profiles to reduce procurement and stockholding costs.

Topsides and jacket weights are comparable to more traditional North Sea designs at about 650 tonnes and 3,500 tonnes, respectively, for a 100-m (328-ft) water depth platform, with almost all of the topsides and much of the jacket being identical for any platform regardless of water depth. However, there is scope for significant savings in project schedule by both reducing setup times and by allowing construction to start in parallel with detailed design. The design is so standardized that water depth, seabed conditions and well slot arrangement are the only pieces of information required to completely define an individual platform, further reducing project schedule and minimizing construction risk.

WorleyParsons sees an immediate market for at least 20 lowcost modularized platforms in the Norwegian sector of the North Sea alone and is talking to several operators who have been carrying out studies to assess their viability. They also see applications in U.K. waters, where the upcoming 30th licensing round will be targeting small pool discoveries that will require especially low-cost development schemes.

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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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New drilling technologies could give us so much oil

New oil drilling technologies could increase the world’s petroleum supplies six-fold in the coming years to 10.2 trillion barrels, says a report released today by market research firm Lux Research.

The most common and controversial technique is hydraulic fracturing, or fracking, in which chemical-laced water is injected to break up subterranean rock formations to extract oil and natural gas. But the Lux report details a host of exotic so-called Enhanced Oil Recovery (EOR) technologies—from solar-powered steam injection to microorganisms—that could be used to extend the life of old oil fields and gain access to so-called unconventional petroleum reserves like oil sands.

“In light of current oil prices, the peak oil hysteria and projection of $300 [a barrel] prices of a few years ago seem overblown – if not outright silly,” the report states. “But in a sense, they were accurate forecasts of what would have happened if EOR technologies had not come online and made unconventional oil reserves – which vastly exceed conventional ones – accessible.”

But don’t ditch your electric car just yet. The development of such technologies is predicated on high oil prices – at least $100 a barrel – to offset the costs and induce a conservative industry to invest in and deploy new methods. And many of the technologies are still young.

Moreover, as we’ve seen with fracking, political opposition to technologies that could pollute the environment and use lots of water could derail their use. And as climate change accelerates, opposition to carbon-intensive extraction of fossil fuels and their expanded use is sure to grow.

Still, here are some of the technologies startups and multinationals alike are pursuing:

Thermal intervention injects steam into wells to extract heavy oils or oil sands. The problem is, it takes a lot of energy to generate that steam, so some oil companies are turning to solar energy instead of natural gas or other fossil fuels. Chevron, for instance, has deployed solar fields built by BrightSource Energy and GlassPoint Solar at old oil fields in California to help recover heavy petroleum.

Chemical EOR injects polymers and alkaline compounds into oil fields to help loosen oil from rock formations and push it into production wells. The China National Petroleum Corporation is the leader in this method, which it is betting will be 20% more efficient than just flooding wells with water to bring oil to the surface. But in the US, expect opposition to introducing large volumes of chemical underground anywhere near water supplies. Some other drawbacks: Chemical EOR doesn’t work well in oil reservoirs where temperatures are high and there’s a lot of salt and sulfur.

Microbial EOR uses environmentally benign microorganisms to break down heavier oils and produce methane, which can be pumped into wells to push out lighter oil. The technology dates from the 1950s but only recently has it been put to limited use. An experiment with microbial EOR in Malaysia, for instance, increased oil production by 47% over five months. But oil and gas engineers are not biologists, the report notes, and may be reluctant to embrace the technology.

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Well’s Production prediction with Microseismic Technology

With efficiency being crucial when every dollar counts, operators in unconventional plays could add microseismic technology to fracture modeling methods to gain insight into permeability advances and better forecast production.

That’s according to Sudhendu Kashikar, vice president of completions evaluation for MicroSeismic Inc.

Understanding drainage volume and improved permeability of stimulated rock are essential to forecasting production, he said. Typically, several models are used to accomplish this, but the approach has its drawbacks.

A single frack model per stage ignores geological variations along the wellbore. Plus, a discrete fracture network (DFN) model is needed to determine how fracturing actually improves the permeability of stimulated rock, Kashikar said.

Microseismic techniques can simplify the workflow and help with production forecasting, Kashikar said during a webcast June 16.

“Technology and procedures were developed to discriminate the microseismic events and fractures described by these events, capturing propped versus unpropped fractures,” Kashikar said while describing Productive-stimulated rock volume (Productive-SRV) technology. “A rock volume capturing the proppant-filled refractures showed much better correlation to the cumulative production than the total stimulated rock volume.”

Productive-SRV technology estimates how much stimulated fracture remains open through proppant placement by using estimated target zone productivity, a DFN, propped fracture estimate and the Fat Fracture drainage estimate, according to MicroSeismic’s website.

Focus is usually on the location of the proppant, but focus should also be on the amount of improved permeability achieved within the SRV or the Productive-SRV, he said.

Understanding and measuring such improvements will lead to the next step in reservoir stimulation and production forecasting, he said.

Using microseismic data has proven beneficial in establishing a deterministic DFN, which shows fractures detected through seismic.

“For every microseismic event we describe a fracture plane. The size is guided by the magnitude, and the orientation comes from the focal mechanism,” he said. “This is much easier to do with surface microseismic.”

The model is calibrated to actual fluid volumes pumped for a well. A mass balance approach is used to fill the fractures with proppant starting from the wellbore moving outward until the proppant is consumed for that stage, Kashikar explained. Once the fracture network and the propped network have been established, a geocellular grid can be superimposed to obtain the SRV and productive SRV to capture the proppant-filled rock volume, he said.

“One advantage of this workflow is the ability to capture fracture intensity—the number of fractures, the orientation of these fractures—to quantify the permeability enhancement achieved,” Kashikar added.

Key steps for the production forecasting workflow are describing three reservoir volumes—the productive SRV (the propped fractures), total SRV (includes propped and unpropped fractures) and the permeability scalar for individual cells within each region to determine how permeability improved for neighboring cells.

This workflow, he said, captures not only the size and shape of the drainage volume but also permeability within the drainage volume.

The process is a big step forward, he said, in understanding and determining the effectiveness of hydraulic fracturing.

“Rather than relying on a single representative fracture model, we can fully and accurately capture the variable fracture geometry and fracture intensity for the entire length of the wellbore, providing a much better production forecast,” Kashikar said. “We can now use the productive stimulated rock volume and the stimulated rock volume with permeability scalars to directly and explicitly describe the reservoir volume in the reservoir simulator.”

Source: www.epmag.com

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Expandable Liners Technology in Oil Gas Drilling

The first hanger designs specifically developed to run liners were true to their descriptive name. The weight of the liner set mechanical slips in a vertical well, and cement was used to seal the liner top. These were mechanical devices that lacked reliability, particularly in deviated wellbores.

As wells were drilled to greater depths, more reliability was needed and eventually obtained through the use of hydraulically set hangers. Once directional drilling and horizontal completions became more prevalent, many equipment suppliers adapted existing technology to the changes in well construction, with more focus on the running tools. 

More robust running tools ensure liners can be deployed in deviated wellbores that require torque, washing and reaming. However, the basic concept of using slips with a cone remains at the heart of all conventional systems, and options are added to this basic offering to aid in functionality and reliability such as dual cones, liner top packers and high-strength running tools.

Trends in liner hangers

The latest developments in running liners include metal-formed liner hangers. Expandable systems have dominated development in liner hanger technology for the past 10 years. These systems are popular because of increased setting and deployment reliability. The advances in technology are apparent through the popularity of the expandable systems and the enhanced applications in different well profiles around the world. Still, expandable systems using hydraulic pressure to set the liner top come with their own risks (e.g., high hydraulic pressure on the rig floor). Other limitations include continued complexity, potential leaks in connections and incompatibility with some rig operations.

To combat these challenges, Seminole Services developed the Powerscrew Liner System, a tool utilizing a metal-forming process that does not require high hydraulic pressures and eliminates the risks associated with reaming to setting depth. The Powerscrew is a torsionally set metal-formed liner hanger that works by converting torque from the top drive into linear force to set and seal a liner top.

The assembly is deployed on drillpipe and conveys the liner to total depth (TD) with a unique running tool. In many cases, running a liner to TD requires compression, rotation and circulation. This is especially true for longer laterals, so special design emphasis has been placed on the running tool, which can take higher compressional loads associated with reaming.

The Powerscrew Liner System is tested at the Catoosa Testing Facility in Hallett, Okla. (Source: Seminole Services)

The Powerscrew’s running tool is designed for both torque and compression while setting the liner top. As a result, these loads transfer more easily through the running tool during liner deployment.

The system includes a patented helical stretch method of metal-forming using a multi-lead rifling (MLR) mandrel. The MLR mandrel provides micro-upsets, increasing the post-formed collapse, and it counter-rotates to eliminate residual torque. In addition, helical stretch forming has less friction and therefore requires less force to forge a metallic tubular downhole. The tool incorporates a high-strength clutch that disengages the running tool from the liner upon reaching setting depth and initiates the metal-forming process with the application of torque. The wellsite operator monitors the torque gauge and weight indicator to ensure proper operation.

Liner hanger market trends

A deep dive into the liner hanger market gives credence to the idea that liner size and weights matter tremendously. With the trend in U.S. drilling focused on shale plays along with the downturn in offshore activity, there has been a shift in demand from larger tools to smaller ones. Increases in demand for liner hanger tools such as the 4½-in.-by-7-in. and the 5-in.-by-7-in. stem from the increased use of liners in horizontal sections common in U.S. shale production. The continuing increase in drilling longer lateral sections also will provide more meaningful savings to those operators choosing to run liners.

Operators drilling more complex wells have facilitated alternatives in well construction that allowed metal-formed liner systems an entry path while also providing multiple options to conventional system offerings. Liner hangers no longer, these well construction tools were built to withstand tortuous well paths and high loads, adding complexity. The tradition of hydraulic setting methodology transferred to the newer expandable systems can still suffer from difficulties souring hydraulic horsepower from the rig. Given that longer laterals will continue to be the trend in producing from shale, less complex tools that can withstand the rigors of deployment in horizontal wells will offer a viable solution to operators. Since rotary drilling rigs are readily available to deliver torsional power through drillpipe, the Powerscrew offers an alternative in metal-forming methodology.

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