The learning curve for the oil and gas industry is steep and fast. In less than six years, the shale boom has seen the Bakken play top 6 Bbbl of oil. The evolution into the intelligent completion of the future will be an integrated solution that goes from the downhole hardware through the production infrastructure all the way to the desktop.

Whether it is technology for deepwater completions, redesign of completions in horizontal wells or new christmas trees for hydraulic fracturing and shallow-water wells, the industry is looking for ways to improve.

For example, operators must decide whether refracturing a well will be a viable and economical option. As part of the evolution of completion technology, operators must concentrate on finding wells where the completion quality was not optimized. Improved recovery can be gained from recompleting conventional wells. Refracturing existing wells costs a fraction of what it costs to drill new wells.

There is even more emphasis on well integrity in the deepwater Gulf of Mexico (GoM) after the Macondo disaster. U.S. Department of Energy’s National Energy Technology Laboratory is working to unravel how foamed cement impacts well integrity in deepwater wells. A team was formed to conduct a thorough assessment of the research needs of the current state of knowledge regarding deep offshore cementing. As a result of the study, five research areas were identified for further analysis.

Christmas trees for offshore and onshore completions also are evolving to meet industry demands. Even though a lot of money is being spent on deepwater development in the GoM, the industry is turning its attention to shallow water on the outer continental shelf. A new generation of diver-assisted trees has been designed specifically for subsea development by jackup rigs.

With the increased use of hydraulic fracturing, trees are also evolving. Increased safety and reduction in the height and weight of frack trees has also led to lower costs.
Finally, intelligent completions have come a long way since their inception in the late 1990s. New systems are experimenting with electronics and fiber optics to avoid the wellhead complexity of hydraulic lines.

E&P’s senior editors have compiled the latest technology in the latest evolutions of completion systems.

Refracturing the right wells could increase ROI

Unconventional wells may have more life to live than previously thought.

By Amy Logan, Senior Editor, Production

It’s never easy to admit that a well was not fully optimized the first time it was completed. As production drops off in wells with hydrocarbon reserves still in situ, operators must decide whether refracturing the well is a viable and economical option.

“It’s hard to expect anyone to shut down a well and refracture it,” said Francisco Fragachan, director of marketing and sales for Pressure Pumping at Weatherford. “It could be considered a high risk. That’s why we’re going to concentrate on wells where the reservoir quality is there, but the completion quality was not optimized. For the time being, we must gain more experience, and our clients must become more confident in the technology.”

According to Juan Carlos Flores, product line manager for restimulation services and multistage completion and production systems at Baker Hughes, steep production declines characterize today’s unconventional shale wells, which typically produce only 3% to 8% of the estimated reserves after the initial completion. The industry is familiar with the improved recovery that can be gained from recompleting conventional wells, but Flores said it wasn’t until recently that operators started considering refracturing their unconventional assets as well.

“Right now, unconventional decline curves are reaching, on average, 85% in about three years,” he said. “With the focus on short-term return on investment [ROI] and low-cost completion design, most of the hydrocarbons are left in place. Once initial production rates drop, the well is shut off and a new one is drilled.”
However, this practice of shutting down an unproductive well and moving on to drill a new well instead is not always the best answer, Flores said.

“The focus should be on creating more effective wells that offer operators increased ultimate recovery,” he said. “We know that refracturing can restore and even surpass initial production, and the same well can be rejuvenated several times—maybe five times or more based on what we’ve seen in the conventional space,” he said. “This will require completion programs designed to sustain the entire unconventional production life cycle.”

Determining feasibility for refracturing
It’s important to understand that each well is unique and there is no “one size fits all” solution for improving oil recovery now or later, Flores said.

“Working with the operator up front to analyze the economics and understand the reservoir is a critical part of the process,” he said. “The intervention has to be tailored to that well, so we need to have an extensive understanding of its performance, drilling and completion history, and reservoir characteristics. With this information we can generate predictive modeling that helps us visualize and estimate the potential return from each zone and further customize the refracturing program to best suit the operator’s objectives.

“This is a different approach than just picking out a gadget at a hardware store,” he added. “We want to understand the needs of the customers and work closely with them to determine the optimal solution based on a carefully planned, data-driven approach.”

Fragachan said communication was crucial and that operators should understand up front that not all wells can be successfully refractured and recompleted.
“The first thing we do is ensure the well is a candidate and make sure refracturing it makes sense,” he said. “We first select candidates that have good reservoir quality and reserves. Second, we consider the diversion possibilities during fracturing treatments. There must be an opportunity for improving the efficiency of the completion.”

Before fracturing the new zone, the producing zone must be plugged back, he said. With the right technology and process, the plugged zone can eventually be unplugged. The previous production can be combined with production from the newly fractured zone and can increase the overall production rate of the well, sometimes significantly. However, refracturing a well is a delicate operation that has to take natural reservoir heterogeneities into consideration, Fragachan said.

“Once you initiate a hydraulic fracture with multiple entry points, the fracturing energy tends to travel in the path of least resistance,” he explained. “So once a fracture has been initiated at an entry point, it is very difficult to divert the energy to initiate a fracture into another entry point.”

In fact, he said diversion is the primary challenge to adequate fracturing; it is what makes the candidate selection process so important, and it explains why not all wells will make good candidates for refracturing operations.

Realizing the ROI

Production across horizontal wellbores varies widely by fracturing stages, Fragachan said.

“One of the first papers that caught our attention stated that 80% of production comes from only 20% of fracturing stages,” he said. “That is obviously not ideal. There were also papers that stated between 30% and 40% of perforation clusters do not contribute to production. So we began to look at that and understand why that is.”

Fragachan said Weatherford will publish two papers with the Society of Petroleum Engineers on recent refracturing successes in the Northeast area of the U.S.
“We went back to a well originally fractured in 2008 that was a good candidate for a refracture,” he said. “The old perforation clusters had to be effectively sealed with a nondamaging, reliable system before we could perforate new zones. The well was basically treated in six prefracture batches, temporarily sealing 26 existing perforation clusters before we fractured 24 new perforation clusters.”

The downhole pressure signature allowed the Weatherford team to understand what was happening in the well, he said.

“We basically shut each of the existing perforation clusters down one by one and then initiated and fracked each of the 24 new clusters, diverting from one stage and from one perforation to the other,” he said. “Then, at the end, we had the ability to put the well back into production—with all 50 clusters producing. That was important.”

Fragachan said that ability to refracture a well and have it produce significantly better than before has made a good ROI case for operators who might have been hesitant about the practice in the past. He added that “anything above 20% is significant.”

“It’s called ‘refracture’ actually perhaps incorrectly,” he said, “because we’re not actually fracturing into an existing fracture. We’re entering into a horizontal section of a well—a new unfractured formation that is in contact with the well—and adding production within that new stage.”

Ready, set, refracture

As the industry begins to realize the benefits of improved production and overall economics associated with refracturing, the practice is likely to gain more traction in the industry, Flores said. Refracturing existing wells costs a fraction of what it would cost to drill new wells, he said, and the opportunity goes beyond the wells that already exist.

Advancing the knowledge of wellbore cementing practices

Review of wellbore cements and cementing practices leads to technological advances.

By Jennifer Presley, Senior Editor, Offshore

Perhaps the only thing more boring to watch than paint drying is cement curing. It is a slow process to observe with the naked human eye as all of the really interesting action is happening at a microscopic level. But how does one know when the curing is complete or if it is where it should be? Or how high temperatures and pressures may impact the stability of the cement?

On the Earth’s surface, it is easy to spot if the cement is in the right place or to make the necessary measurements to determine if it has set up properly. But taking those measurements and monitoring the emplacement of wellbore cement hundreds or thousands of meters downhole? That’s a far trickier process and one that researchers at the U.S. Department of Energy’s National Energy Technology Laboratory (NETL) are working to unravel.

Setting a knowledge baseline

Wellbore cement integrity is critical to the safe and successful drilling and production of hydrocarbons from wells. As more and more wells in the Gulf of Mexico (GoM) are being drilled in increasingly extreme environments—water depths greater than 2,743 m (9,000 ft) to subsurface targets in excess of 6,096 m (20,000 ft)—concerns regarding the cement barrier in the wells have also increased. Subjected to a variety of temperature, pressure, in situ and formation conditions, the integrity of the cement over the lifetime of the well has generated many questions. The Deepwater Horizon incident brought many of these questions to light.

To find answers to these questions and to determine where knowledge gaps exist in the state of knowledge on wellbore cementing, researchers at NETL conducted a six-month review of cementing practices and conditions of offshore wells.

Following the Deepwater Horizon spill, “The explosion and subsequent environmental disaster made everyone readily aware of the significant research needs with respect to wellbore integrity in the Gulf of Mexico,” said Barbara Kutchko, research scientist in NETL’s Office of Research and Development. Based on that event and the preliminary findings of the Ocean Energy Safety Advisory Committee, an industry regulatory nonprofit advisory group led by the Department of Interior, NETL “formed a team to conduct a thorough assessment of the research needs of the current state of knowledge regarding deep offshore cementing.” The assessment was accomplished by interviewing industry experts and conducting an extensive literature review. Industry experts came from a variety of major oil, gas and service companies and members of the American Petroleum Institute, Society for Petroleum Engineers, International Association of Drilling Contractors and Drilling Engineering Association.

From that review, five research challenges were identified:

  • Developing new wellbore integrity monitoring;
  • Understanding cement stability in field conditions;
  • Ensuring quality control;
  • Understanding the impact of temperature- and pressure-induced stress; and
  • Improving standard calculations.

These five challenges are the focus of R&D efforts currently underway at NETL with partner universities and industry collaborators from across the U.S.

Tackling the challenges

Efforts are currently underway at NETL to address the challenge of understanding cement stability in field conditions. Currently, foamed cement is the system of choice in the high-stress environment of the GoM, in shallow flow environments, and increasingly in deepwater and ultradeepwater wells, according to Kutchko. However, knowledge about the behavior and performance of this cement under in situ conditions is relatively sparse.

Foamed cement is a gas-liquid dispersion that is produced when an inert gas like nitrogen is injected into conventional cement slurries to form microscopic bubbles. It is used in formations that are unable to support the annular hydrostatic pressure exerted by conventional cement slurries. Being lighter in weight and more resistant to temperature- and pressure-induced stresses and having superior fluid displacement have helped to make foamed cement systems a popular choice.

But their increased use has made understanding stability in the wellbore environment vital. For example, gas can coalesce and cause gas pockets to form and rise in the cement column if the foam cement is unstable. Unstable foams can, according to Kutchko, result in failure to achieve zonal isolation. A stable foam will be able to provide the desired zonal isolation when installed properly in the wellbore.

To better understand the stability of foam cement, Kutchko and her team are comparing lab-generated foam cement samples that are tested at atmospheric conditions against those generated in the field.

Traditionally, “when foam cements are tested, they're generated at atmospheric conditions. Yet we know foam cement, just by the nature of the material, will behave very different in a well,” she said. “Pressures, temperatures, shear—those types of parameters—will affect the behaviors and properties of the foam cement. What we don't know is how it affects the properties. We don't know what happens. That has been the primary focus of the foam cement project.”

The goal of the project is to develop a predictive relationship between the gas distribution and the physical properties using the lab’s CT imaging capabilities as well as mechanical geophysical characterization methods, she added. Kutchko and her team are looking at three datasets: foamed cements prepared according to the API RP 104-B under atmospheric conditions, foamed cements generated and collected in the field at various pressures, and those generated in the laboratory under a range of in situ conditions using a foam generator that is on loan from project partner Schlumberger.

“We have a suite of atmospheric prepared foam cements using a couple of different industry surfactants and stabilizers, and we are looking at those across a range of foam qualities,” she said. “Foam quality means how much entrained air or nitrogen is in the cement. For example, if I say it’s a foam quality of 20%, it’s 20% air or nitrogen.”

The spirit of cooperation between industry and government also plays a key role in the acquisition of field-generated samples.

“We’ve been very fortunate to have had three of the major service companies to date—Baker Hughes, Halliburton and Schlumberger—provide us with field samples. These are foam cements that were collected using actual field equipment,” she said, “the same full-scale industrial equipment and methodology that is used to generate cement in a well. This has never been done before; nobody's ever seen samples like this. This has provided us with a very unique set of samples that are highly significant to this project so that we can look at actual field conditions vs. laboratory conditions.”

Initial findings

What Kutchko and her team are discovering is that the field samples are very different from the lab-generated samples.

“What we’re finding is that the lab samples and the field samples don’t look anything like each other,” she said. “Basically, in the atmospheric cement we measured permeability, proxy and strength. They all held out very well in the foam quality range that you would expect in a well. What we're seeing in the CT scans of the field-generated samples is a significant distribution of small bubbles,” she said.

Work is still underway to understand the differences between the lab and field samples. For example, the data on the mechanical testing are still being collected.

“The foam cement project is still going strong,” Kutchko said. “We’re right in the middle of it, and we’re just beginning to understand these systems. We’re laying down the foundation, and as we begin to understand how these systems work and bring in our modeling capabilities, then we’ll start to understand the long-term integrity of wellbore cement.”

Work also is starting in other areas of cement research.

“We’re also starting to utilize our CT scanning capabilities and expertise to look at other parameters, other challenges, other research needs in the well,” she said. “For example, right now we are looking into the effect of temperature and pressure cycles on the integrity of cement with respect to zonal isolation.”

Editor’s note: For more information about this project and products of this research see edx.netl.doe.gov/offshore.

Offshore, onshore trees designed for safety, specific applications

From an onshore horizontal frack tree that reduces bending stress to newly developed shallow-water trees, service companies are adapting equipment for safety and reducing costs.

By Scott Weeden, Senior Editor, Drilling

With the large number of acquisitions of assets in the shallow waters of the Gulf of Mexico (GoM), finding and developing smaller fields near existing infrastructure is now in vogue. Given the smaller reserves, cost effectiveness is the name of the game in developing these oil and gas deposits.

Service companies are developing equipment to address the issues involved in working in shallow water. Diver-assisted trees that can be installed from jackup rigs provide a much less expensive method for developing these fields.

At the same time, development of unconventional reserves with horizontal drilling and hydraulic fracturing is requiring some new approaches to the design of onshore frack trees. By reducing height and weight on frack trees, costs and safety can both be addressed.

Shallow-water systems

Although much of the emphasis on development in the GoM is in deepwater, operators are now focusing renewed efforts in shallow waters to tap smaller fields. FMC Technologies is offering its shallow-water subsea Jackup X-mas Tree (JXT) for operators wanting to exploit stranded reserves near existing infrastructure.

The JXT is “fully optimized for shallow water. It is based on FMC Technologies’ deepwater production systems and has been simplified with fewer functions compared to our deepwater offering,” explained Henning Gruehagen, business manager, shallow-water systems, FMC Technologies, at the 2014 Offshore Technology Conference.

The trees have been standardized for 10,000 psi and are in stock. These are fully compliant with API standards. The mudline tree can be operated by divers or ROVs in water depths to 130 m (430 ft) and is adaptable to any mudline suspension system. The tree can be delivered in four to six months, thus improving economics, lowering installation costs and reducing abandonment and salvage costs.

These trees are designed for stranded reserves near existing infrastructure in jackup applications. The fields would typically be within 16 km (10 miles) of existing platforms with excess production capacity. The wellheads are suitable for exploration, development or injection wells.

“With this tree, the well can be tied back subsea to existing infrastructure, which is much more cost-efficient than adding a new platform,” Gruehagen explained.
There are three shallow-water JXT tree options available: JXT-1, JXT-2 and JXT-3. The JXT-1 is a diver-assisted installation with a 31/16-in., 10,000-psi block tree system with up to 31/16-in. or 21/16-in. annulus access. It is capable of four downhole hydraulic penetrations and has a 10-year design life.

The standard JXT-2 configuration is for diverless, ROV-assisted installation with a 41/16-in., 10,000-psi block tree system with up to 31/16-in. annulus access. It is capable of one electric and three downhole hydraulic penetrations. It has a 10-year design life.

Finally, the JXT-3 tree is for diverless and ROV-less installation on a mudline suspension system or a UWD subsea wellhead. The 51/8-in., 10,000-psi block tree system allows seven downhole functions (five hydraulic and two electric). It is designed for a 20-year life.

Frack trees go horizontal

Even though the downhole tools needed for hydraulic fracturing and production are important, the surface equipment for fracturing operations is also key to increasing efficiency, improving safety and cutting costs. The emphasis on more stages and higher hydraulic horsepower has led to the redesign of surface frack trees for unconventional wells.

The most effective hydraulic fracturing treatment is dependent on a reliable and effective frack tree. To this end, these surface frack trees recently evolved from conventional frack tree configurations to now include a horizontal frack tree configuration. As they have been developed to reflect industry needs, this new design configuration has been an incremental improvement in efficiency, reliability and safety of the fracturing operation.

The F-T90 horizontal tree from Cameron offers an ultracompact footprint and reduced height and enhances the integrity of overall fracturing operations. This tree is built to reduce bending stress at the tree connection. It can be operated with pneumatic, hydraulic or electric actuation. The system is designed to handle 15,000 psi.

For a 5 1/8-in., 15,000-psi system, the horizontal tree represents more than 50% reduction in size and about 25% reduction in weight from a conventional frack tree. Built to minimize the bending moments induced by the cycling of high-pressure pumps during fracturing operations, the new horizontal tree has a substantially reduced moment arm that minimizes bending stress at the wellhead and tree connection. With two valves and a flow cross integrated, the horizontal tree’s compactness offers quicker installation in the field and is less susceptible to leak paths. The design also offers a buffer zone to offset erosion.

Safety remains paramount in all fracturing operations, playing a big role in the development of the horizontal design. In the past, an operator had to be raised up to the frack tree to perform operation or maintenance, but with the horizontal design, the need to raise the operator up to the tree in a man basket is eliminated.

Downhole intelligence

From pie-in-the-sky ideas to modern reality, intelligent completions continue to push the envelope.

By Rhonda Duey, Executive Editor

The concept had many names—Intelligent Wells, the Downhole Factory, the Field of the Future. But all of these monikers described a new form of completion technology that would give operators the ability to better control their wells downhole.

The term “intelligent completions” is often used to describe a variety of different technologies that have evolved over the past 10 to 15 years to address operators’ needs. In its infancy the concept spawned several highly ambitious ideas.

“There was originally a vision of these fully autonomous wells that would control themselves and provide the ability to self-optimize and have wireless communication up the wellbore,” said Darrin Willauer, director of intelligent production systems at Baker Hughes. “We had the vision of the downhole factories where all of the separation would happen downhole. There were a lot of crazy concepts being tossed around back then.”

But there also were some compelling drivers. For one thing, drilling technology was undergoing dramatic changes. “The industry’s key challenge was how to drill wells to intercept and maximize the contact with the reservoir,” said Mohamed Aly Sadek, completions marketing and technology manager at Schlumberger. “We started with horizontal wells, then extended-reach, and now multilaterals. The drilling technology started to evolve very fast, and what used to be out of reach in the ’80s and ’90s is a common practice today.

“While this was happening, many challenges started to come up. We could drill the wells, but how could we complete them and produce them efficiently? It became very obvious that the current completion technology was no longer suitable.”

Another very real driver was the rising cost of well intervention, particularly offshore. “People didn’t want to go in and move a sleeve because they wanted to shut off a zone that was producing water,” said Savio Saldanha, senior product manager for intelligent flow control at Halliburton. “That meant they would have to mobilize a rig just to do a sleeve movement on one well. Given the expensive day rates, it didn’t make economic sense.”

The need for intelligent systems also was driven by the difficulty of obtaining production logs in horizontal sections or multilateral wells. Sadek said that in a multilateral well only the mother bore can be logged. “You can have four or five laterals in the same well,” he said. “We cannot ignore the production coming from these wells.”

So intelligent completion technologies were developed. Early deployments were relatively simple, combining flow control valves with pressure and temperature sensors. As they have evolved over time, these systems have become more complex, but they also have provided tremendous benefits to the industry.

Current technology

Saldanha outlined numerous situations that have benefited from intelligent completions. They help reduce opex and capex by enabling commingling of zones with different pressure profiles. They can shut off water or gas breakthrough from particular zones. And they can enable the production of marginal assets.

“If you have a smaller asset that is only going to produce 50,000 bbl overall, it doesn’t make economic sense when you’re spending $100,000 to drill a well,” he said. “But if you’re drilling it as part of a major find and you use intelligent completions to extract whatever comes from that marginal reservoir, those are incremental reserves.”

Operators also are using intelligent completions for secondary and tertiary recovery, particularly in water injection wells to control the sweep, he said.

Technology enhancements are having an impact as well. Willauer said that downhole flow meters enable operators to determine the amount of production coming from each zone, or each well in a subsea completion. Fiber optics are also playing a larger role since this technology enables distributed sensing.

But key challenges remain. One of the major questions regarding intelligent completions is how to power the downhole instruments. Early electric systems were notoriously unreliable. “It’s not like a drilling tool that’s going to drill the well and pull out,” Sadek said. “We have to design a system that will stay downhole for at least 10 years.”

So the industry moved to hydraulic systems and hybrid systems combining both electronics and hydraulics. Early versions of the hybrid system were also plagued by reliability issues, and Saldanha said that any electronic failure in the system caused the operator to lose control of the well. Hydraulic systems are much more reliable, but the wellbore can get pretty congested with multiple lines.

“Real estate is beginning to be reduced,” he said. “You might need a line for a safety valve, for injection, for gauges, for other valves. Pretty soon you end up with eight or nine lines.”

The industry is slowly revisiting the idea of all-electric systems as reliability has improved. Baker installed an all-electric system several years ago that is still functioning properly, but many operators are still hesitant to embrace the technology.

Weatherford, meanwhile, relies on a radio-frequency identification (RFID) system in a wireless completion set-up. “When you move into a wireless scenario, you have to talk about downhole power generation,” said Yvonne McAnally, global product line director, upper completions for Weatherford’s Well Completion Technologies division. “Our RFID system is powered by batteries. We can actuate a sleeve without any control lines. But we have the restriction of the lifespan of the batteries.”

Tendeka has licensed technology from Statoil to produce its FloSure autonomous inflow control valve, allowing operators to even out the inflow profile to prevent fluid coning. The valve operates by responding to the velocity of the fluid coming into the well.

Finally, there is the issue of cost. While intelligent completions might save a subsea well from watering out, the systems are becoming so complex and expensive that operators might begin to question their return on investment.

“Some operators might struggle with the cost-benefit proposition since the benefits are not realized until several years into the future,” McAnally said. “They might be wondering if there is a better way.”

What is needed

While intelligent completions technology has come a long way from its early beginnings, most agree that it’s still evolving. The main issues driving current development are simplicity and integration.

“We have to simplify these systems in terms of the number of control lines and the number of electric cables,” Sadek said, adding that Schlumberger is perfecting an integrated platform that can be deployed as one piece of kit. The first generation, the IntelliZone Compact modular multizonal management system, was launched about four years ago, and he said that many customers who are not usually early technology adopters have been asking for the system.

Willauer agreed that an integrated system is more than the sum of its parts. “There is no one key technology,” he said. “It’s really the aggregation of all of these technologies that is enabling multiple markets right now. It’s not just the high-end markets. We can provide solutions for some of the lower end markets now.”

He added that the intelligent completion of the future will be an integrated solution that goes from the downhole hardware through the subsea infrastructure all the way to the desktop. “It’s that level of intimacy and integration that we need to continue to pursue,” he said.

The challenge in realizing a fully automated intelligent completion will require more than the participation of the completions engineers. Sadek said that it’s necessary to work closely with the drilling department to understand their well construction plans. “There’s no value in drilling a well if we can’t complete it,” he said. “We have to have a clear understanding of how they’re going to be drilling the wells.”

And production engineers need to be involved as well. “I see a blending of the completions engineer and the production engineer,” Willauer said. “The completion design is impacted by the production goals to a much greater extent than it has been in the past.”

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