Richard Molloy, ExxonMobil Development Company, attributes the success of a challenging gas shut-off workover operation on Russia’s Sakhalin Island to the planning and design efforts of a multifunctional team.

By Katie Mazerov, contributing editor

ExxonMobil Development Co last year completed a challenging workover campaign on Russia’s remote and environmentally sensitive Sakhalin Island, effectively shutting off gas-producing zones and restoring oil production in two extended-reach horizontal offshore wells at depths greater than 9,000 meters (29,500 ft). A case study of the operation, SPE/IADC 163482, was presented by Richard Molloy, ExxonMobil Development Company, on 5 March at the 2013 SPE/IADC Drilling Conference and Exhibition in Amsterdam. “The project incorporated rigorous planning, design and flawless execution by a multifunctional team that continuously focused on safety, operational integrity and attention to the environment,” Mr Molloy said. The operation involved installing straddle liners with swell packers inside the existing lower completions to shut off the gas-producing zones.

With some of the world’s longest-reach wells, Sakhalin Island, off the eastern coast of Russia, presents several operating challenging, including limited access and infrastructure, extreme temperatures reaching as low as -40°F, a short drilling window, seismic activity and difficult road conditions, he explained. The two target wells, Z3 and Z5, have total depths (TD) of 10,675 meters (35,000 ft) and 9,168 meters (30,000 ft), respectively, and are located in 10 to 60 m (32 to 196 ft) of water in the region’s Chayvo development.

After drilling the wells in 2005, the operator began observing increasing gas-oil ratios. Attempts to shut in the wells and cycle production were unsuccessful, so the wells remained shut in for extended periods. The wells initially had been completed in open hole with pre-drill liners, standalone screens across high-permeability and weak zones, inflow control devices and swell packers across multiple zones, Mr Molloy said

Technical challenges

The workover operation, launched in November 2011 and completed in January 2012, incorporated lessons learned from a previous successful workover operation on shallower wells in the region. “However, the greater depths of wells Z3 and Z5 presented additional technical challenges, including the need to precisely place small tubular straddles and mitigate drag risk while conveying the tubulars through tight clearances,” Mr Molloy said.

Before initiating the actual workover, the team had to move a cold-stacked rig with a 180-ft mast and 35-lb substructure from a location 75 km (46 miles) north of the workover site. “The team spent several months dismantling the rig that was moved in 1,400 truckloads over challenging road conditions impacted with deep mud and snow drifts,” he described. “The total rig start-up operation involved more than 350,000 manhours.”

The workover involved many steps that included well-kill operations to displace annular and tubing fluids into the formation without surfacing hydrocarbons. After monitoring well pressures to ensure the wells were dead, the upper completions were pulled, the wells cleaned out and the depths correlated. Preparations were then made to run the lower completion straddle liner packages, which included a 5-in. liner with two 9-meter swell packer assemblies placed above and below the target zones to mitigate depth uncertainty and ensure sufficient contact was made between the packer elements and a short section of blank pipe in the existing lower completion.

The upper completions were run with bottom seal assemblies, production packers, downhole pressure and temperature gauges, deep and shallow gas lift mandrels and surface-controlled safety valves. After testing the tubing and setting the swell packers, waiting for the packers to sufficiently seal, the wells were reconnected to the production manifolds and brought back online.

“We completed the well workover operations ahead of schedule and under budget, with no lost-time and no safety incidents or environmental spills,” Mr Molloy said. “The success of the campaign can be attributed to the team putting significant emphasis on meeting the functional objectives of the project while minimizing operational complexity.”

Ronnie Witherspoon, executive vice president of Nabors Completion & Production Services.

Rush into manufacturing mode may be leading to less efficient frac designs, forfeiting valuable information, production in shales

By Katherine Scott, associate editor

Ronnie Witherspoon is executive vice president of Nabors Completion & Production Services.

What technological challenges do you see in the provision of completion and production services, and what equipment improvements will be needed in the future?

If you look at the estimated ultimate recovery using unconventional drilling and completion practices, the numbers are a stark contrast to what we see in conventional oil and gas production, where ultimate oil recovery may have exceeded 20% over the original oil in place, so there’s room for significant improvements in current completion technology.

The reserves being produced today are often more geophysically complex in nature and much harder to reach from a drilling perspective. These reserves often require advanced completion techniques in order to be economic.

These challenges are being met with new technologies and novel applications of existing technologies, as well as the careful application of best practices. The industry will certainly witness an increase in fracture network efficiencies in the reservoir contact area and the implementation of improved secondary recovery techniques.

As we continue to optimize the fracturing process, the industry will have to move toward greater automation. The drilling side of the industry has become largely an automated process. This development has substantially lowered manual labor requirements. However, the completion process, including hydraulic fracturing, continues to be highly labor-intensive. There is significant room for improvement in the automation of that facet of the business.

How should a well be designed for successful fracturing?

We’ve seen a complete rush into the shale plays, so the urgency to exploit the play to extract hydrocarbons in a rapid fashion has really put the industry into a manufacturing mode mindset. This practice has unfortunately marginalized the science needed to optimize each well utilizing a tailored engineering solution. It is critical to account for certain variables, such as closure stress, permeability and conductivity, and fluid efficiency in order to ensure that we are designing a fracturing recommendation that results not only in the highest recovery for the initial production but also in the optimal production decline over time for each well.

In many of these basins, operators are utilizing more wells per pad. Instead of one well, industry now sees anywhere from four to 20 wells per pad, and the geologies don’t vary a great deal so operators default into a manufacturing mode.

This shale concept of drilling multiple wells on a pad is somewhat new to the industry. You drill one well over and over, replicating that process. A cookie cutter approach is, however, not always the most optimal approach.

Has this manufacturing mode of drilling been beneficial for the industry?

It’s a double-edged sword. Operators can look at some simple injection tests that may have been performed in the past on certain fracturing treatments in order to gain valuable knowledge about the formation.

Indeed, it’s becoming common practice now for companies to utilize the relatively cost-effective procedure to gain information on initial wells.

Nabors conducts a fracturing operation in Jane Lew, W. Va. One challenge to hydraulic fracturing is the increase in fracturing capacity and decrease in demand. “All of that right now puts us in an unbalanced situation that over time will take care of itself,” Ronnie Witherspoon, executive vice president of Nabors Completion & Production Services, said.

Unfortunately, a lot of companies are sort of defaulting to this replication approach after the initial well design is implemented, which may or may not be a bad thing, but it’s ultimately a blind reliance on initial sampling. It can result in the forfeiture of valuable information about certain anomalies or complex faults or structures that persist in the underlying formation.

Do you believe industry needs to improve how they understand these reservoirs?

Over time, operators will realize quicker cash flows from producing wells in that replication mode, but that can lead to less efficient frac designs. For example, proppant selection is still critical for the longevity of the well and, as formations become deeper and more complex in structure, the overall natural stresses from the well production can lead to proppant embedment and crushing, so understanding the connectivity implemented by the initial fracturing treatment is important.

Ascertaining the closure stress present in an individual well is a prerequisite to an optimal proppant selection process and can help ensure that an operator’s investment can and will lead to maximum recovery over the lifespan of the well.

Fracturing operations require trucks to move materials to location. How is industry working to reduce road use during fracturing?

As an industry and definitely at Nabors, we’re focused on increasing driver training and education. In addition, we have raised the bar with regards to the selection and criteria that must be met by new drivers. Across the board, the industry is using more stringent hiring practices around driver selection. There is also heightened focus on increased control injury management for vehicle movements and monitoring between locations.

Another issue surrounding fracturing is water management. How does industry approach this task?

Water resource plays a critical role in our management strategy. The drilling of deep saltwater wells for hydraulic fracturing has become more common, but both saltwater and water reuse techniques require fluids design technology that is capable of resisting brines and other water mineral characteristics, so the oil and gas industry has focused its efforts on “green” chemical initiatives. More and more, industry has viewed water as a key resource central to the operation of the business.

The manner in which water is being obtained, managed, processed, stored and utilized as a critical asset is a high priority for our industry. Technology is playing a key role in the water management cycle for utilization, filter and reuse. Addressing this challenge requires an “all in” strategy, including the use of flowback and produced water in completion methods in large-scale drilling, as well as stewardship and the conservation of surface water. It will make the use of deep saltwater wells to source water for oil and gas operations increasingly more commonplace.

What specific technologies can you point to that are addressing this?

We’re looking at technologies for overcoming these obstacles with a focus on new completion fluid designs, with increased tolerance for brines and other minerals in the water while meeting the challenges and requirements of unconventional wells. Additionally, new technologies of filtration and purification continue to come into the marketplace, addressing the challenging water conditions encountered by the industry.

What do you see as some of the biggest challenges to hydraulic fracturing?

Nabors operates in Jane Lew, W. Va. The company currently does not have stimulation operations outside of North America but is looking to expand its footprint in the major shale basins around the world that have commercial productivity, such as Argentina, Colombia, Mexico, the Middle East and potentially China.

The market in the US is a bit challenged right now. We’re in an oversaturated state, so it sort of exacerbates the people situation when you want to continue to attract and retain the best people, but you have to find the fine balance in it. We’ve just undergone a transition from the more gassy areas to the liquid-rich areas, so we’re still balancing that out.

If you look at some of the commercial challenges, not only have we seen the frac capacity increase, but also we’ve seen a decrease in the demand side. Service intensity has also fallen, causing incremental reductions in demand based on redeployment of frac capacity to lower-intensity places, i.e., the oil and the liquid plays from the gas plays.

We’re starting to see a greater adoption of certain completion techniques that reduce time post-frac, which exacerbates this overcapacity situation. We’re working closely with clients to establish and reduce that time for fracturing, and the reduction of frac stages per well in the gas plays. All of that right now puts us in an unbalanced situation that over time will take care of itself.

How does Nabors address challenges on the regulatory front?

Both as a production and service company, we’ll have to continue to comply with a host of local, state and federal regulations in the US, as well as regulations from foreign governments, including taxes, financial reporting, air and water emissions, transportation, and product use and disposal. There exists an extensive procedural regime for applying and receiving key permits and licenses. There’s a lot of misinformation out there, and as an industry, we’re going to have to continue to work closely with the public and the regulatory authorities to ensure that the existing regulatory and permitting process and framework makes sense.

Do you see industry expanding its fracturing operations around the world?

Nabors doesn’t have stimulation operations outside of the US other than Canada right now, but we are looking to expand our footprint in the major shale basins around the world that have commercial productivity. Our drilling group has a sizeable footprint in the international markets, and we want to leverage that to establish a footprint on the stimulation side in key areas like Argentina, Colombia, Mexico, the Middle East and potentially China.

How has industry approached the fracturing issue in relation to its public image, and how should it be approached going forward?

We have to continue to educate the public. There’s a lot of misinformation about the industry that really stimulates an irrational fear about our business. The industry has to encourage public media-based educational programs. We have to continue to have town hall meetings that are informative and worthwhile at the local levels, but at the end of the day, the industry’s detractors will always seize upon the uncommon occurrences and make an improper characterization of the industry as a whole.

We’ve got to do a better job at combating some of the things that are improperly characterized and instruct the public about the significant technologies, safeguards and procedures that we’re all driven toward and that we’re committed to implement in order to ensure safe operations throughout the industry.

Nabors lives in the communities that it works in. Safety drives every aspect of our business, so the industry should not embrace more regulations just for the sake of more regulation, but what we should do is work in a collaborative effort with the public and regulators, and develop a regulatory framework that makes sense for the industry and for the public.

I think that our goals are far more aligned than what some of the industry detractors would have the public believe.

Do you think industry is doing enough to improve environmental performance so that is comparable to its safety initiatives?

We look at environmental performance as a key piece to our ongoing strategy to preserve and protect the well-being of our people and communities. It’ll continue to hold the same priority it does for us to protect and serve our people, so when I say safety, I talk about our environmental efforts as well. They go hand and hand

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Baker Hughes’ IN-Tallic disintegrating fracturing balls disintegrate over time for unimpeded production in unconventional shales.

Fracturing, stimulation advances fuel production boom, reduce environmental impact; next-gen innovations focus on increasing overall, IP rates

By Katie Mazerov, contributing editor

It’s no secret that unconventional shale production is booming in North America, and the news keeps getting better as industry continues expanding into new oil and liquids-rich plays. So bullish is the outlook for shale oil, the International Energy Agency (IEA) has projected that the US will overtake Saudi Arabia as the world’s largest oil producer by 2020.

“When it comes to unconventional shale fracturing and completions, the US is the center of the universe,” said Rob Fulks, director of shale resource projects for Weatherford. “Not every country is blessed with these great expanses of shale that hold tremendous potential to meet global demand for increased oil and gas.”

Still, challenges remain. Recovery rates remain in the single digits, considerably lower than in conventional reservoirs. Wells also see steep decline rates after initial production (IP). This is driving operators and service companies to continue developing technologies to boost recovery and improve economics and efficiency while at the same time reduce the environmental footprint and comply with increasing regulations.

Whereas the drilling side of the business cracked the horizontal drilling code that made unconventional production possible, the completion side of the equation still has work to do beyond multistage fracturing. Over the past 10 to 12 years, industry has learned that the geologic variability of shale reservoirs means production is inconsistent and uneven. To that end, the focus is now on finding solutions to improve monitoring, better understand and connect to the reservoir, identify and target the sweet spots, enhance fracturing and stimulation and proppant distribution and even re-fracture to boost rates in older, nonproductive wells.

Whiting Petroleum uses advanced open-hole technology to fracture a well in the Sanish formation in the Williston Basin. Whiting has completed nearly 500 wells in the basin’s Bakken and Three Forks plays, all with an open-hole design that takes advantage of natural fractures in the reservoir.

“Ultimately, improved recovery, both overall and IP rates, is what we’re looking for,” said John Paneitz, senior operations engineer for Whiting Petroleum, one of the largest operators in the Williston Basin’s Bakken and Three Forks plays, which is characterized by complicated geology and extended-reach laterals with measured well depths as long as 20,000 ft. “Overall recovery is low in shales because the reservoirs are generally poorer quality than conventional reservoirs, which have higher-quality rock that allows the hydrocarbons to flow much better. We’ve picked the low-hanging  fruit; today there are more reservoirs that are poor quality, and we’ve gotten better at accessing them.”

Halliburton’s CleanWave mobile water treatment service enables treatment at the site for recycling produced and flowback water.

Looking to capitalize on multistage completion technology, operators have increased the number of stages and fractures to access more rock. “We are now running 40 stages, shrinking the distance between each of those stages down to less than 300 ft,” Mr Paneitz said. But even that strategy has limits. “We saw significant results when we went from 10 to 20 stages and some improvement when we went from 20 to 30 stages,” he said. “But  we’re starting to see diminishing returns on 40 stages because when we add more stages, we also increase the cost.”

Whiting has drilled nearly 500 wells in the Williston Basin, all with an open-hole design that uses swell packers for annular isolation. “We like open-hole technology because we can take advantage of the natural fractures,” Mr Paneitz said. In the vast majority of those wells, frac sleeve technology, as opposed to the conventional plug-and-perf method, is used for fracturing.

The sleeves, containing specially designed ball seats, are shifted open with frac balls to expose ports for fracturing. Advances in sleeve design have made the technology possible in wells with 30 or more stages. Using the open-hole packer and sleeve completion design, Whiting has seen both improved economics and a reduction in days on location, which translates to HSE benefits and lowered risk, he noted.

Baker Hughes’ DirectConnect ports allow the well to be fractured in the sweet spots for optimum recovery. Increasing connectivity with the payzone has been an important driver behind the latest generation of the company’s FracPoint multistage fracturing technique for open holes.

Looking ahead, Mr Paneitz believes fluids and fluid surfactants that improve recovery of oil from rock will be the next big breakthrough. Farther down the road is the idea of refracturing, which he says cannot be done with the same multistage design. “At this point, we would have to do a ‘Hail Mary’ operation and hope the fracture goes where we think it should.”

Four years ago, Whiting installed reclosable frac sleeves as a long-term experiment with the idea of refracturing the well or wellbore sections to reestablish production at a later date. The operation has not been carried out, primarily because the company is focused on new production. “When there is a well on every corner, which we’re quickly hitting, then we can go back and revisit older wells to refracture,” he said.

Among the ongoing challenges the industry is beginning to tackle is the inconsistent production resulting from the intense variability of unconventional plays. “The industry has done a fantastic job of improving the cost of these wells, which we can drill and complete very quickly,” said Kyel Hodenfield, vice president, unconventional resources for Schlumberger. For example, to reduce costs and improve efficiency in cemented plug-and-perf operations, the KickStart pressure-activated  rupture disc valve is being installed as part of the casing string in the first stage, or toe, of many wells to allow for stimulation without the need for coiled tubing or other intervention.

While driving down costs is important, however, operators really want to improve the cost per unit of production. “That means eliminating bad wells by locating the sweet spots and then optimizing the completion,” Mr Hodenfield said, citing IHS data indicating that as many as 60% of the wells in a given play are uneconomic, due to the heterogeneity and variability of the reservoir.

“Operators are often surprised that what they thought was going to be a productive well actually is not.”

Schlumberger is integrating seismic technology with core and wireline logging data from vertical pilot wells to study the properties of the reservoir to identify the sweet spots, which is a combination of reservoir quality and completion quality parameters. “With this integrated reservoir-centric workflow approach, we’re measuring effective porosity, pore pressure, natural fractures, hydrocarbon saturation and whether the formation will be receptive to a fracture filled with proppant,” Mr Hodenfield explained. “Many reservoir sections do not have the proper composition, stress or texture that produces a viable fracturing system.”

Mangrove software’s unconventional fracture model (UFM) uses pre-existing natural fractures and a mechanical earth model to simulate fracture geometry. Microseismic data is superimposed over the UFM results for comparison.

Due to the variability, the completion effectiveness also varies along the wellbore. “We have run production logs in hundreds of horizontal multistage wells and have identified inconsistent production, with more than 40% of the perforation clusters and 20% of the stages not contributing to production,” he continued.

To achieve more consistent results, the Mangrove reservoir-centric stimulation design software uses the integrated workflow approach to devise a seismic-to-simulation model that designs a complex fracture ahead of time by taking into account the reservoir geology and geomechanics and properties of the rock.

“We can’t assume these reservoirs are homogeneous,” he said. “Rather than place perforation clusters every 100 ft, which is the way many wells have been addressed, we have proven it is more productive to engineer the completion and vary the stage lengths based on the composition and fabric of the rock and then locate the perforation clusters where stresses are similar to achieve a simultaneous breakdown.”

Schlumberger’s HiWAY service creates infinite fracture conductivity in vertical and horizontal wells.

Schlumberger’s HiWAY flow-channel hydraulic fracturing service increases production while significantly reducing water and proppant. Combining chemistry, fibers and a pumping schedule, proppant treatment is pulsed while the fibers are pumped continuously. The fiber keeps the proppant together in pillars, creates channels and then dissolves into fluid after the operation is completed.

The technology is being used in most plays on nearly a third of the company’s hydraulic fracturing jobs. In the Eagle Ford, wells using the technology showed a 32% production increase over wells completed with crosslinked gels after 90 days and a 37% increase after 250 days. Compared with slick water, production rates using this technology showed 67% and 87% increases after 90 days and 250 days, respectively.

“With HiWAY we reduce the amount of proppant by about 40% and eliminate up to 60% of the water. Over the past 18 months, the reduction of water and proppant has already eliminated over 40,000 transports to and from the well site,” Mr Hodenfield said.  “We want to do more with less – less proppant and water, fewer people and trucks.”

Halliburton’s CleanStream mobile unit uses ultraviolet light rather than chemicals to control bacteria in water used for hydraulic fracturing operations.

Sustainable stimulation

While recovery, efficiency and economics are priorities for operators, reducing the environmental impact while improving sustainability of the stimulation process remains critical. Halliburton’s CleanSuite portfolio of production enhancement technologies for hydraulic fracturing and water treatment is a three-tiered approach to addressing that challenge, said Nicholas Gardiner, strategic business manager, production enhancement. The CleanStim fracturing fluid, 100% sourced from the food industry, reduces chemical exposure risk at and below the well site; the CleanStream service uses ultra-violet light instead of chemical biocides to control bacteria; the CleanWave system recycles water through electro-coagulation, minimizing waste and the use of chemicals.

While the shift from gas production to oil has not had a major impact on completion methods, it has resulted in a swing away from water-fracturing techniques to gel and crosslinked gel techniques. “The move to oil increases the requirement for a highly conductive fracture, and we’re seeing an emphasis on surfactant technologies and gels with less residue,” Mr Gardiner said.

Last year, Halliburton introduced PermStim, a robust fluid system to improve fracture connectivity using a derived natural polymer rather than guar.

Among other basins, the system was deployed in the Eagle Ford play, in a fracturing treatment in a 6,050-ft horizontal well section at 10,897-ft vertical depth with a bottomhole temperature of 280°F, where the operator saw a 20% increase in average initial production. It has since been used successfully in more than 100 wells, primarily in the Williston, Denver-Julesburg and Green River basins at temperatures up to 300°F bottom static temperature.

Another challenge in the low-permeability shale basins is proppant distribution. Halliburton’s AccessFrac suite of stimulation services improves proppant distribution in multizone completions and includes features designed for refracturing treatments, infinite conductivity and enhanced development of complex fracture networks. “This ensures operators that multiple perforated intervals can be fracture-stimulated at the same time, without inserting isolation plugs between intervals,” Mr Gardiner said.

Software technology relevant to improved recovery includes Halliburton’s new Knoesis service that interprets microseismic knowledge in real time and integrates that information into the fracture design during the fracturing operation. “This involves two disparate technologies talking to each other in real time – applying microseismic or monitoring technology into the pumping schedule while we can actually use it to optimize recovery,” said Ron Hyden, Halliburton’s technology director for production enhancement.

Looking ahead, industry will continue to push for incremental improvements in recovery rates, he believes. “The single-digit recovery rates have not been on the industry radar because we’ve been able to get by with them. But as operators recognize that low recovery rates are not acceptable, they are pushing to improve the economics. We need to look to the science community to determine what about shale rocks makes recovery so marginal, versus classic sandstone or carbonate formations.

“Shale has some unique characteristics that will make it necessary for us to make modifications in our chemistry and production methods,” he continued. “I anticipate that our laboratories will do more work in the development of geomechanics and technologies often referred to as digital rock, where we analyze the formation at a micro level to better understand the mechanics that drive fluid movement.”

Increasing connectivity with the payzone has been an important driver behind Baker Hughes’ latest generation of its FracPoint multistage fracturing technique for open holes. The latest design allows a single ball to open up to five sleeves per stage to direct fracturing treatment into the formation. Each FracPoint MP sleeve includes eight DirectConnect ports placed 45° around the circumference of the sleeve.

The system can be used as an alternative to the plug-and-perf method in up to 17 stages per well, eliminating the need for cementing the liner in place.

“The system was developed based on information we’ve received from reservoir analyses indicating that by controlling the initiation point of fractures in some wells and reservoirs, we can gain significant improvement in the productivity of the well,” said Ed Wood, product line manager for unconventional completions at Baker Hughes. “We start by understanding the reservoir, drilling the well in the right place, gathering data along the wellbore to identify the sweet spots and then placing the sleeves in the sweet spots so that when we fracture the well, we gain the best opportunity for the most recovery.”

The system allows as many as five sleeves to be opened with one IN-Tallic fracturing ball, which disintegrates over time, he explained. When the ball is dropped, it passes through the sleeves, with the first four sleeves subsiding into a recess to allow the ball to land in the final fixed sleeve. When the sleeves are opened, hydraulic pressure launches the DirectConnect telescoping ports into the formation with up to 15,000 lbs of force.

The impact of the ports into the formation changes the near-wellbore stresses and creates the path of least resistance in the formation, which helps control where the fracture initiates, Mr Wood continued. This allows the operator to directly influence where the fractures are, rather than the fracturing occurring at the naturally weak points in the formation.

These sleeves not only allow multiple initiation points per stage but also the accurate placement of the fracture treatment, ultimately giving better connectivity to the reservoir.

“When compared to cementing with plug-and-perf operations, this method can deliver significant time and cost savings for operators,” Mr Wood said. “Along with directly targeting the optimum places to fracture, we’re getting more sleeves and hundreds of connections to the reservoir with fewer balls, which have the added feature of disintegrating with time.” The system has so far been deployed successfully in North America, including Alaska. “We are evaluating those operations and looking at how this technology can be best used internationally,” he added.

Looking ahead, Mr Wood believes unconventional completions will continue to increase in North America and blossom in other areas globally.

“We believe that by using reservoir models that integrate log-derived, near-wellbore geomechanical and petrophysical properties from calibrated seismic data, operators can optimize well placement and completion design earlier in the reservoir life cycle for more efficient construction and improved recovery,” he said. “Technology combined with field experience will lead us into the new reservoirs.”

Top: NSC-Tripoint’s ball-dropped cementable frac sleeve can be used in multizone operations where cement is either preferred or required due to the type of formation. The system was designed to reduce the amount of water and horsepower needed on location. Bottom: The STIMMAX completion system allows operators to open up to five valves per stage, with five points of entry, all manipulated with one ball. Suited for both cemented and open-hole applications, the method effectively stimulates an entire horizontal wellbore, up to 20 stages.

Cementable Solutions

NSC-Tripoint, which provides downhole completion tools and services for all the major US shale plays, has expanded its STIMPACT portfolio with a ball-dropped cementable frac sleeve (CFS) for multizone operations where cement is either preferred or required due to the type of formation.

The STIMPACT CFS replaces the conventional plug-and-perf method, the stimulation technique still used in 75% of unconventional, horizontal wells, explained Ryan Henderson, operations manager/business development – unconventional completion services for NSC-Tripoint.  The system enables one point of entry for each zone; the ball is dropped from the surface, landing on the frac sleeve ball seat. The frac sleeve will then be manipulated by differential pressure, allowing proppant and pad, acid, slick water, N₂, CO₂ or the applicable stimulation option to enter the formation to begin the stimulation process.

“Customers needing cement for isolation to help pinpoint and project fracture placement can use this technology to increase their efficiency, reduce the amount of water required and reduce the amount of time they need horsepower on location, which is a huge part of the spread costs,” Mr Henderson said. “It also provides greater accuracy in targeting the sweet spots and effectively draining the formation.”

The technology was successfully used in the completion design of a well in the Marcellus play, deployed in the first five stages of a 14-stage hybrid system.

The company’s STIMMAX completion system for cemented and open-hole applications, commercialized in the last year, allows operators to open up to five valves per stage, with five different points of entry, all manipulated with one ball. The method effectively stimulates an entire horizontal wellbore, up to 20 stages, allowing for continuous fracturing and increasing recovery with fewer balls.

“This technology represents a big step forward for the industry by providing the machinery and advanced rubber for seals and O-rings to deliver an effective product that will successfully stimulate the formation, save time and cost, and provide more reliability and also provide limited entry, which is a preferred stimulation method,” Mr Henderson said.

Whereas a 20-stage operation using the conventional plug-and-perf method would likely require seven to 12 days to bring a well on production, both the STIMPACT CFS and STIMMAX systems can reduce that time to one to three days, Mr Henderson noted.

“We’re evolving to provide the technology and solutions our customers want, reducing service costs and helping operators gain a return on their investment in a third of the time.”

Weatherford’s i-ball system uses a one-size ball, rather than graduated ball sizes, to open an unlimited number of seats, which ultimately disappear. The technology maintains internal diameter and eliminates the need to mill out the balls.

Eye on the ball

Weatherford’s ZoneSelect open-hole completion portfolio has been enhanced to include the new i-ball multizone frac sleeve that optimizes production, reduces operational costs and increases efficiency in shale wells. “Most of the efficiency and production improvements we’re looking for today are on the completions side,” said Eric Blanton, global product line director for Weatherford’s Lower Completions division.

The i-ball technology uses a one-size ball, rather than graduated ball sizes, to open an unlimited number of seats, which ultimately disappear. “This opens up new doors for customers needing 40 zones because the internal diameter doesn’t need to be reduced with each sleeve and because it eliminates the need to mill out the balls,” Mr Blanton said.

Initially designed for the Bakken market, the technology has been used successfully in a number of extended-reach wells in the play but can be deployed in both open hole and cemented wells, he noted. Weatherford plans to launch the sleeve in 5 ½-in cased wells and has also tested the system for 4 ½-in casing.

Weatherford fracturing service technicians put the final high-pressure components together for a shale completion about to be pumped. Along with new technology, Weatherford believes that significant advances are likely to emerge from the ability of service companies to finally access long-term production logs that are providing important lessons for the industry.

The ZoneSelect MASS frac sliding sleeve provides an alternative to plug-and-perf operations, particularly for cemented wells. The sleeve can be placed between isolation packers in multizone completions, or cement can be used for isolation.  “This type of completion comes closest to mimicking a plug-and-perf application because when we drop one ball across the interval, it opens multiple sleeves and allows us to fracture across that interval through all the sleeves at the same time,” Mr Blanton explained.

“It is particularly beneficial when fracturing across multiple perforation clusters to create a transverse fracture.” The system is being used in the Eagle Ford play, where cased-hole completions are still the preferred method, as well as in the Marcellus region and Canada.

For operations requiring coiled tubing (CT) stimulation, the ZoneSelect CT system can open unlimited zones with isolation devices, also eliminating the need for milling. The technology, which monitors pressure along the CT string and facilitates real-time adjustments for each zone, is being used in the northern Bakken region in Canada and will be deployed for applications in the Eagle Ford play, Mr Blanton said.

But along with new technology, significant advances are likely to emerge from the ability of service companies to finally access long-term production logs that are providing important lessons for the industry moving forward. “Up until now, we’ve seen a fairly geometric pattern in these completions – same size stages with uniform distances between perforation clusters,” Mr Fulks said. “But, we’re learning that these operations aren’t nearly as efficient as they need to be because we didn’t take the time to place perforations at the most potentially productive intervals to begin with. Now, we’re starting to look outside the box by studying our logs and cuttings analyses and placing perforation clusters where they have the highest probability of success. We’re beginning to see significant improvement in overall performance simply by putting a little bit of science behind what we do.”

KickStart, Mangrove and HiWAY are marks of Schlumberger.

FracPoint, FracPoint MP, DirectConnect and IN-Tallic are trademarked terms of Baker Hughes.

STIMPACT, STIMPACT-CFS and STIMMAX are trademarked terms of NSC-Tripoint.

ZoneSelect and i-ball are registered terms of Weatherford.

Pat York, global director of well engineering and project management for Weatherford, speaks with Drilling Contractor associate editor Katherine Scott about the need for service companies and operators to collaborate earlier in the well construction process in order to address complex challenges.

By Pat York, Weatherford

Well engineering and project management services are providing a powerful collaborative interface with operators for exploring, designing and implementing integrated well construction solutions. Drilling exploration and development wells can present complex overlapping problems that overwhelm the discrete, technology-oriented methods that typify the drilling process. This traditional approach is often unable to encompass a scope of challenges that range from concerns about meeting AFE targets and complying with regulations to mitigating risk.

Instead, the solution is being found in an engineering and project management approach focused on the operator’s end objective of constructing an optimal, high-integrity, on-target wellbore.

The process starts with concept development by the service company using the operator’s basis of design to identify and examine new options. In a collaborative environment, operator and service company experts refine the concept to produce a fully engineered well plan, and then execute it.

The step-by-step process involves pre-engineering, project assessment, identification of resources, creation of a project plan, a detailed engineering study, and implementation of the plan at the wellsite. Project management serves a pivotal role that integrates various technology solutions and streamline interfaces between clients, multiple product lines, operations and suppliers.

If service companies collaborate earlier with operators, costs can be reduced, enabling operators to meet AFE targets. A recent well in an ongoing project offshore South America applied this approach and has provided a new path for developing the difficult and costly field.

The engineering and project management service approach has evolved with the growing complexity of well construction and the corresponding jump in sophisticated and often overlapping non-traditional technologies and methods.  Applied on a global basis in well sections, wells and fields, the approach is successfully addressing significant challenges to wellbore construction.

A recent well in an ongoing project offshore South America exemplifies the approach. Successfully applied in its first application, the well plan developed through the process is providing a new path forward for developing the difficult and costly field.

A significant number of prior wells using conventional well construction methods had been unsuccessful. At issue were depleted zones that commonly occurred when drilling the main boreholes to initialize sidetracks. Over an eight-year period, attempted sidetracks had experienced as much as 281 days of NPT. Some of those wells cost more than $85 million each, were non-productive and had 100% NPT.

A collaborative well engineering approach with the operator was engaged to find new options for the well construction conundrum. The executed well design successfully mitigated the issues and met all well objectives by combining managed pressure drilling (MPD) and reaming with casing (RwC) technology to overcome the unstable and underpressured zones.

A parallel team of an operator and a service company brings together a critical mix of knowledge and experience. The two perspectives and utilization of each other’s strengths contribute to an effective engineering team for developing well construction solutions.

A collaborative process

Central to the success of such an undertaking is a collaborative emphasis that builds a detailed understanding of well construction objectives and challenges. Operator and service company experts work in teams through phases of exploration (i.e., analyzing of the well’s challenges), engineering and execution to ensure that options are thoroughly examined and solutions fully vetted.

The project exploration phase begins with understanding all the challenges from the operator’s perspective. It is important to know how they have interpreted the data to arrive at their basis of design and their expectations in drilling the well.

On the basis of this information, well engineering service company experts look at alternatives from their perspective. A set of technical solutions and roadmaps are developed to describe various options. These scenarios are examined and challenged in collaboration with operator engineers to produce a set of vetted well design alternative concepts. 

Engineering the concepts

These concepts are turned into a workable plan through upfront engineering that integrates well construction technologies and best drilling practices to most effectively deliver the well objectives while addressing its challenges.

Combining upfront engineering with the best-matched well construction technical solutions achieves the level of risk mitigation and economic viability needed to ensure operational success in difficult applications.

The engineering phase applies industry-accepted engineering best practices and leverages internal synergies and global expertise to design an optimized well plan.

It assigns the risk associated with applying various technologies, delivers multiple options across various hole sections, creates the front-end engineering design (FEED) study, and provides recommendations for the well design.

The well engineering begins with collecting a more detailed data set and concludes with the FEED study from which the well can be drilled. Continual collaboration is essential to the process. The detailed engineering analysis on proposed technical solutions requires a high level of communication that is facilitated by similar disciplines with complementary skills sets and capabilities. This parallel team makeup not only ensures that the respective experts can talk collegially with one another, it also brings a critical mix of knowledge and experience.

In this mix, the operator’s engineering strengths are typically geared to exploiting assets and minimizing exploration and development risks while the service company’s engineering expertise is aimed at minimizing risk while applying technology and advanced drilling methods. The two perspectives contribute to an effective engineering team for vigorously developing well construction solutions.

For example, in geophysical and geological activities, the operator’s analysis strengths are complemented by service company expertise focused on risk analysis and mitigation during the engineering and execution of the drilling and completion technical solution application engineering and operations. Additionally, in practice, the operator is engaged in cross-vendor integration and project management while the service company is tasked with technical solution project management.

Executing the plan

With the finalization of the engineering studies for each technology solution, the FEED study is prepared and the project moves to the field and the execution phase.

The transition at this step is particularly important. Plans developed in the engineering phase must be fully reviewed, understood and accepted by all of the operations teams (operators, drilling contractors and service providers) for the execution to be successful. To ensure this level of communication, operations engineers are typically involved in the engineering phase. Their engagement helps refine the well plan(s) and confirms it is fully optimized and executable with the operational risks minimized.

On the rig, training is conducted so that safety and operational efficiency are optimized while minimizing operational risks and the plan can be precisely executed. While a best practice in any application, the step has added importance with the introduction of new procedures and methods to standard rig operations. 

The end game

From the beginning, well planning has one chief objective – construction of a high-integrity wellbore according to design. Incorporating service company engineering and project management in the process, from concept to execution, introduces new options for achieving that objective. These integrated technical solutions are successfully mitigating long-standing operational and economic well construction challenges.

For completion equipment, Baker Hughes has developed general guidelines for elastomers on what is acceptable for use. The company recommends hydrogenated nitrile elastomers in typical applications, for service up to 50-psi partial pressure up to 250°F, but if the temperature is above that mark, the H2S concentration can only be 10-psi partial pressure.

Industry looks to fit-for-purpose equipment, new guidelines for extreme H2S environments

By Katie Mazerov, contributing editor

Like vinegar in a cylinder of honey, hydrogen sulfide (H₂S) is the industry’s ultimate party-pooper, a sour intruder that puts the damper on an otherwise healthy well that may hold a wealth of hydrocarbons. Better – and perhaps aptly – known as “sour gas,” this naturally occurring but toxic and highly corrosive chemical has always lurked in the oil patch. However, over the years, producers have been able to either manage it in low concentrations or avoid the problem altogether by moving on to other fields.

As global energy demand increases, however, operators can no longer be choosy about which reservoirs to tap, and completing wells with high concentrations of sour gas is a challenge that many companies can no longer avoid.

Sour gas is a condition complicated by high-pressure, high-temperature (HPHT) environments that often exist in areas where oil companies are pushing the boundaries of production – notably ultra-deepwater, where pressures can exceed 20,000 psi. It is produced with oil and natural gas in varying concentrations.

“Because of its corrosive properties and toxicity to humans, operators must be very careful to use properly rated metals and materials in wells with concentrations of H₂S,” said Marco May, senior technical sales manager for Vallourec & Mannesmann, manufacturer of premium Oil Country Tubular Goods (OCTG). Although it is seen in pockets globally, sour gas is prevalent in the Middle East, North Sea, US Gulf of Mexico (GOM) and areas of the former USSR, such as Kazakhstan, he added. Unlike carbon dioxide (CO₂), which has a more long-term effect on materials and is more predictive in determining failure, the effects of sour gas occur much faster, sometimes in a matter of 12 hours.

“No one has come up with a process that reduces or eliminates sour gas, and in low concentrations, H₂S is manageable,” said Peter Fay, packers product line manager for Baker Hughes. “It depends on how corrosion-resistant the metallurgy of the equipment – tubulars and casing – is that is being put downhole. Considerations also must be given to the selection of elastomers for O-rings and packer elements.”

To that end, the industry looks to NACE International. NACE provides education, training and certification for various industries, promotes research of new technology and advocates on behalf of corrosion experts. NACE MR0175/ISO15156 establishes requirements for materials that can be used in H₂S environments in oil and gas production.

“Our mission is protecting people, assets and the environment from the effects of corrosion,” said Linda Goldberg, director of technical activities for NACE. “This has historically been our most widely used standard.” The standard specifies requirements for metal materials that make up the equipment used in sour gas environments, the chemical composition of those materials, the temperatures to which those materials can be heated and other environmental factors that affect the material.

The standard was first published in 1975 and has undergone several revisions. In 2003, it was adopted by the International Organization of Standardization (ISO). The 1975 standard covered only wellhead components. In 1977, the Texas Railroad Commission requested that the industry provide a standard for all oil and gas production equipment exposed to an H₂S environment after an equipment failure caused a fatality.

People can request changes or have materials added to the standard using a ballot process. Ballots approved by NACE are submitted to the ISO for final approval. “Between 2003 and 2009, about 15 ballots were approved and included in the 2009 revision of the standard,” Ms Goldberg said.

There are also two testing standards associated with the primary standard: TM0177-2005, “Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking and Stress Corrosion Cracking in H₂S Environments,” and TM0284-2011, “Valuation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking.”

Failures of wellhead equipment and carbon steel tubular goods during the 1950s prompted action by the industry and NACE to define causes and develop possible remedies. The failures involved 13 Cr martensitic stainless steel wellhead components and carbon steel tubing with strengths greater than 100,000-psi yield strength, explained Robert N. Tuttle, a NACE fellow who was on the committee that developed the 1975 standard. “The failures of susceptible steels were identified as being caused by applied tensile stresses while being exposed to H₂S. Laboratory and field data demonstrated that susceptible steels were those that were of high strength and could be detected by use hardness measurement.”

Through its VAM product line, Vallourec provides Oil Country Tubular Goods for three levels of resistance to sour service environments as defined in NACE MR-0175/ISO15156: Mild Sour (Region 1); Intermediate Sour (Region 2) and Severe Sour (Region 3).

Rockwell C hardness (HRC) measurements were chosen as the method of choice since field hardness testing devices were available. New guidelines limited metal hardness to a maximum hardness of 22 HRC for carbon and low-alloy steels. “Some of the early failures occurred rapidly after exposure to H₂S – often within minutes,” Mr Tuttle said. “The failure mode was later defined as sulfide stress cracking. The failures occurred well below normal equipment design stress.”

NACE participates with organizations like the nonprofit group RPSEA, which is engaged in sour gas research on a number of fronts. “The urgency for dealing with this issue is coming to pass because we are going into HPHT regimes in places like the Lower Tertiary of the GOM,” said James Pappas, vice president of RPSEA’s ultra-deepwater program. “The preference is to have a solution in hand before it’s really necessary and avoid making costly mistakes.”

First to consider is the magnitude of the problem, he said. “The empirical equations used to estimate damage from HPHT in a sour environment are inadequate in many cases. We’re having to extrapolate the damage assessment from information we have from laboratory testing.”

RPSEA is launching a project to examine sour environments at various combinations of 350°F and 400°F and pressures ranging from 20,000 psi to 30,000 psi to try and verify the data and, more importantly, to establish new equations.“These new equations can be plugged into models to better forecast what is happening in sour environments and ultimately determine what the best metals are and see if any new alloys need to be created. We know corrosion inhibitors work because we’ve tested them at lower temperatures and pressures. We may need to create new inhibitors at these higher temperatures and pressures, but we won’t know that until we do the analysis.”

RPSEA is also studying the fatigue limits of deepwater risers in H₂S environments. Lab tests put riser materials under different stresses to determine breaking points and understand what happens from a chemical side. “The next step is to verify the lab results by conducting a field test in which we introduce H₂S to actual risers hanging off a platform but not hooked to a well,” he said.

For completion equipment, Baker Hughes has developed general guidelines for elastomers, Mr Fay explained. “It depends on the concentration of sour gas and the temperature of the well, because the higher the temperature, the more susceptible both the metals and elastomer materials are to the effects of H₂S. For example, nitrile rubber can be used safely in wells with a low concentration of sour gas, but once the temperature goes above 175° F, standard nitrile is no longer acceptable.”

For typical applications, Baker Hughes recommends hydrogenated nitrile elastomers for service up to 50-psi partial pressure up to 250°F, but if the temperature is above that mark, the H₂S concentration can only be 10-psi partial pressure. “When we start using more premium elastomers, the standard guidelines switch from partial pressure measurements to percentages of fluid,” Mr Fay added.

Specifications also pertain to an occurrence known as hydrogen embrittlement, where high levels of sour gas cause equipment to crack or break, even in cases where corrosion is not a problem. “For low-end completions, many of our customers will use a carbon steel alloy, but that has limits on the hardness of the material,” he continued. “In those cases, the sour gas concentration is relatively low and corrosion is not a concern, but hydrogen embrittlement can still occur. In situations with a higher concentration of H₂S, operators will choose a 13-chrome (corrosion-resistant) base material. For highly corrosive applications, Inconel is the product of choice.”

The industry has known solutions within a certain boundary of temperatures, and new research is looking at solutions for either higher concentrations of sour gas or higher temperatures. “Once we get outside the box defined by NACE, we’re facing a huge research and development project to develop materials that will meet the standards we strive for,” Mr Fay noted.

“For example, with GOM Lower Tertiary deepwater platforms, we’re typically talking about higher temperatures and pressures, so if sour gas is present in those environments, we are pushing the boundaries of where we haven’t been before. NACE only covers metallurgies up to 450°F, so if we have a sour gas completion that exceeds 450°, we have to do our own metallurgical evaluation of the properties and materials under those conditions because there are no published standards.”

Research is advanced by the major service companies, which have an interest in ensuring the materials can perform. “We are constantly developing HPHT technology to try and push the boundaries,” he said. “We offer many types and models of HPHT equipment – packers, safety valves, liner hangers – and they could all see service in H₂S applications.”

Sour gas is also problematic in high-pressure wells, where there are currently not a lot of accepted industry equipment grades especially when the concentration of H₂S is high. “If we have higher pressures, such as 20,000 psi and above, even small amounts of sour gas are a problem,” Mr May said.  While stronger steel and casing are required to handle depths and high pressure, a more malleable or ductile steel is necessary to withstand the sour gas conditions. “Depending on how deep you drill, the tubulars require a certain tensile strength, collapse behavior and burst pressures that require higher-strength steel.

“But, those products are not acceptable by NACE for use in sour gas environments because they are susceptible to hydrogen embrittlement,” he continued. “Lower-strength steel prevents that issue but isn’t strong enough to meet the pressure.” For example, Vallourec’s VM-125 SS (sour service) is a high-strength steel that has been used for HPHT environments in the GOM with slightly sour conditions, but it is not rated for the most severe level of H₂S as defined by NACE. Addressing that conundrum will require a two-step process, Mr May believes. “We need to develop stronger steels that aren’t susceptible to this type of hydrogen embrittlement, and we need to design heavier-wall casing that still meets all the properties through the wall thickness.”

Through its VAM product line, Vallourec provides OCTG for three levels of resistance to sour service environments as defined in NACE MR-0175/ISO15156: Mild Sour (Region 1); Intermediate Sour (Region 2) and Severe Sour (Region 3).

For extreme environments, the solution is to develop fit-for-purpose equipment. “For completions that encounter CO₂, in addition to H₂S, the choice will be a high-quality alloy for the tubing, such as high-grade nickel, rather than carbon steel,” Mr May said. “We are seeing increasing demand for fit-for-purpose equipment as more and more operators are conducting well testing to better understand the conditions and determine if they need full-scale sour gas equipment.”

Inconel is a registered term of Special Metals Corporation.

VAM is a registered term of Vallourec & Mannesmann.

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The Boots & Coots Pulsonix TFA.  Material is used with permission from Halliburton.

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The Baker Hughes Mastiff. Material is used with permission from Baker Hughes.

Technology advances address water influx, wellbore buildup, seek innovative methods to cut pipe, set cement plugs

By Katherine Scott, editorial coordinator

As fields mature around the world, innovations in well intervention services have become increasingly important as operators work to slow or even reverse declining production rates. Economics is often a driving factor, but cost should never be evaluated in isolation. Products should be looked at by considering both time and cost benefits, Doug Bolingbroke, technical adviser – worldwide drilling for Apache, said. How quickly equipment can be mobilized, as well as going dayrates for a drilling rig versus a well intervention vessel, are key factors to consider.

Operators also must be willing to try new technologies, weighing the potential benefits of innovation against the economics. Providing service companies the chance to field-test a piece of equipment gives operators themselves opportunities to benefit from cutting-edge technology. “When we’re talking with service companies and defining what we want, there’s always a view that we want field-proven equipment, but it’s impossible to have new technology that’s been proven. Someone has to come first,” Mr Bolingbroke said.

Walking the talk, Apache is planning to use a lightweight intervention riser system to permanently abandon wells that allows cement plugs to be set using coiled tubing, whereas a riserless system would be restricted to using wireline. Additionally, the system can be deployed from an intervention vessel, which can be more cost-efficient than using a semisubmersible.

“There is also a significant time saving,” Mr Bolingbroke said, by not having to run an 18 ¾-in. BOP stack, a 21-in. marine riser, or a work string or landing string with a subsea test tree. “This riser system saves all these operations and allows the well work to start much sooner.”

The industry is “right on the cusp of more of this type of equipment,” Mr Bolingbroke said. “As subsea intervention techniques become more reliable and people get more confident with them, there will be more enthusiasm to use them.”

One challenge, however, is that intervention technologies developed for one area may not be suitable for another. For example, the North Sea has many subsea wells that require intervention, whereas the subsea wells needing attention in the Gulf of Mexico are fewer in number but located in deeper waters. “A technique that’s developed in the North Sea is not really applicable or can’t be used in the Gulf of Mexico,” Mr Bolingbroke explained.

Earlier this year, Apache acquired the Beryl Field in the North Sea from ExxonMobil, increasing the company’s needs for intervention innovations that can help to revitalize mature subsea wells. Such needs across the industry are driving service companies to build advanced systems that increase reliability and can mobilize quickly, sometimes through a rigless approach or through one-trip well stimulation.

In any operation, the aim is always to gain better understanding of the well to enable successful interventions on the first try, said Kelly Hebert, manager of the thru tubing tool service line for Boots & Coots. “The more you understand the well, the better it produces and the less well intervention will be required later.”

Weatherford’s WidePak retrofit gas lift tool works to restore production in gas wells suffering from water influx, or oil wells experiencing production decline. The tool extends the reach of lift gas deeper into the well, below the production packer, and directly down to the perforations and production zones to improve the well’s hydraulic efficiency.

Weatherford has introduced the WidePak retrofit gas lift (RGL) system, which can restore production in gas wells suffering from water influx, or oil wells experiencing production decline. “The tool extends the reach of lift gas deeper into the well, below the production packer, and directly down to the perforations and production zones,” Jake Bramwell, global technical specialist for Weatherford’s Thru Tubing Business Unit, said. “In doing so, it improves the well’s hydraulic efficiency, enabling the lifting of fluids, therefore allowing stranded mobile oil and gas in the reservoirs to produce on their own.”

In spring 2010, the RGL saw its first pilot installation in a well for a major North Sea operator. The gas well had not produced in more than two years due to liquid loading issues. “It allowed the operator to do a fairly economical intervention and get good production results without having to perform a costly workover to remediate the water influx issues,” Mr Bramwell said.

The pilot deployment of the system “was the first time anything like this had been attempted in the North Sea, or globally, that we know of,” Mr Bramwell said. A 5 ½-in. RGL pilot system was installed in the nonproductive well to allow access for lift gas to the lowest perforation, approximately 800 ft below the production packer. After successful application of the RGL, production resumed at a sustained rate of 6 mmscfd. The pilot project took 17 days and over 6,000 manhours to execute, leading to four additional North Sea installations in the same field.

Weatherford notes that the RGL has been V0 certified, an IS0 14310 validation grade for packers and bridge plugs confirming the tool exhibits zero gas leaks in use. “Testing packer equipment to a V0 grade is a very time-intensive process, pushing the tool to its mechanical failure limits and requiring multiple differential pressure reversals, temperature swings and often a third-party witness to certify results,” Mr Bramwell said.

The aim is to provide confidence in reliability. “If (a tool) can pass this validation test, then the design is good to go. It’s not going to see anything worse in a field application,” he continued. The packer system has been tested through a temperature swing from 40°F to 325°F  and a maximum differential pressure of 5,000 psi in a gas environment.

“The RGL system is a way to breathe life into old wells that are seeing that decline in production without having to abandon them or do a major workover to try to squeeze the last life out of the well,” Mr Bramwell said.

This fall, Weatherford will begin a four-well RGL installation program offshore for a major operator in Alaska’s Cook Inlet.

Boots & Coots has developed the Pulsonix Tuned Frequency and Amplitude tool, an enhanced fluidic oscillator that removes built-up deposits in the wellbore. When used with coiled tubing or jointed pipe, it enables real-time placement of fluids that treat the area near the wellbore, according to the company.

Besides water intake, reduced production rates can also stem from debris build-up. Boots & Coots has developed the Pulsonix Tuned Frequency and Amplitude (TFA) tool, an enhanced fluidic oscillator that removes built-up deposits. When used with coiled tubing or jointed pipe, it enables real-time placement of fluids that treat the area near the wellbore, according to the company.

The tool, now on its third generation, has two ports – active and inactive. Pumped fluid exits the active port while the inactive port additionally takes in fluid, switching back and forth to generate pulses. A change in the third-generation’s oscillator pattern encourages stronger pulses at the formation and less leakage from the opposing port, Robert Howard, global advisor for downhole coiled tubing with Boots & Coots, said.

“What we’re doing downhole is generating pulses to help break up damage, such as perforating debris or built-up scale that is choking back production,” he described. In conventional tools, acid is pumped down the well, which can force the debris deeper into the formation instead of removing it, he explained. With the Pulsonix TFA, “as we make passes up and down the wellbore, this pulsing allows the damage to be flushed out and removed from the wellbore so it’s not pushed back in there to come back and cause problems later.”

In old wells in particular, the tool can help to remove collected particles that have become obstructions. “For the mature field, it’s better to remove this damage and try to bring on the production,” Mr Howard said.

The tool can be used on land and offshore in new and old, vertical and horizontal wells. “There’s no temperature limit; there’s no pressure limit,” Mr Howard said.

In 2010, the tool was tested alongside a rotating-jet nozzle in thick, Oligocene Sespe sandstone in California. Four onshore wells were drilled vertically and completed with uncemented 7-in. pre-slotted casing. Results were based on surface-injection rate and pressure over a period of 400 days; 200 days of data recorded before the stimulation and 200 days of data recorded after the stimulation until the injection rate and pressure returned to pre-stimulation levels. The wells treated with the TFA nozzle showed an improvement in cumulative injection volumes and immediate post-stimulation rates, the company found. The operating company attributed this to the tool’s cyclic-pressure pulses. Additionally, tool reliability was noted due to the lack of moving parts.

The Pulsonix TFA is undergoing commercialization as well as additional field trials in countries such as Nigeria, Mexico, Egypt and Germany, Mr Howard said. “What this tool is about is essentially making it easier for a well to flow by cleaning up damaged areas,” he said. “The better we clean, the more production we get out of the well.”

Instead of explosives or chemicals, Welltec‘s Well Cutter uses grinding pads made of a metal matrix composite with embedded diamonds.

A growing trend in well intervention is the use of increasingly automated tools, and a key enabling technology is robotics. In particular, downhole robotics is becoming an important tool in the operator toolbox, according to Welltec. “They can be quickly deployed, and without needing rigs, they can go in and fix problems in operator wells,” said Brian Schwanitz, vice president for Welltec.

The company introduced downhole robotic intervention tools to the upstream oil and gas industry 16 years ago with the Well Tractor tool, Mr Schwanitz said, noting that mechanical, clean-out and milling tools have more recently enabled a broader range of operations, such as manipulating or removing stuck valves and other restrictions inside pipes.

A natural evolution of advancing robotics was to create a tool that grinds through the walls of the pipe, Mr Schwanitz said. In February, the company introduced the Well Cutter, a pipe-cutting tool that uses grinding pads made of metal matrix composite with embedded diamonds, instead of explosives or chemicals. Deployed on electric-line, either by gravity or conveyed with a tractor in a high-angle hole, the tool is sent to the desired cut point. Surface commands sent through the wireline activate the tool to set two anchors, one at the top and one near the bottom, to hold it in place.

The Well Cutter cuts a beveled edge so it’s a clean slant, which does not require the normal polishing run to “dress” the cut. The slant cut also allows the cut to be made even when the pipe isn’t in tension.

“Once it’s anchored, these grinding pads open out to meet the inner wall of the pipe, and they rotate slowly to initiate the cut and then increase speed to complete the cut. As the pads grind at an angle, they leave a beveled edge so it’s a clean slant, which does not require the normal polishing run to ‘dress’ the cut.  The slant cut also allows you to make the cut even though the pipe isn’t in tension,” Mr Schwanitz explained. If production has been suspended due to completion problems, for example, and cutting a stuck tubing is required, this can be a low-risk method to sever the pipe without damaging the outer casing, he said. Further, the Well Cutter produces only a fine powder, which does not interfere with future operations.

The Well Cutter saw its first commercial deployment in February with a pipe-cutting operation for Sakhalin Energy on the Piltun platform offshore Russia. Sakhalin Energy had experienced problems pulling the packer on a previous workover attempt. The pipe was 4 ½ in., 12.6-lbs/ft tubing, and total operating time was approximately six hours. The operation was performed in a deviated 57° well at a well depth of 7,000 ft (2,133.6 meters) and with a downhole temperature of 140°F.  The pipe was successfully cut in the first run. By not having to use explosives and chemicals, both safety risks and logistical hurdles for handling these materials were eliminated. “It also saved them from having to go back in and polish off the flaring and all the associated cutting debris that is common with other pipe cuts,” Mr Schwanitz said.

Although a rig will eventually be needed to remove the pipe from the well, the Well Cutter can be mobilized to cut the pipe before the rig arrives, making it a quick solution when explosives or chemicals are not easy to mobilize or a rig is not readily available, Mr Schwanitz said. He adds that Welltec is working to extend the autonomous aspect of downhole robotics by eliminating the power cable. “We are working on a totally wireless set of tools run on batteries that will self-recharge if there is flow from the well. This will be the direction of the future.”

Baker Hughes’ Mastiff is a self-pinning, rigless intervention system that can be used for workovers, abandonments and drive pipe pre-installation operations. The unit can be rigged up in less than two days and is lighter than a conventional rig. To enhance safety, the system has self-erecting features so crews don’t have to be sent up on riding belts to do the assembly.

Even with the best technologies, a mature well will eventually pass the point of production. “The aging fleet of platforms around the world are eventually going to be removed, and you need some efficient and economical way to do it,” David Harris, business development manager for Baker Hughes, said.

Baker Hughes recently introduced the Mastiff, a mechanized, self-erecting and self-pinning, rigless intervention system that can be used for workovers, abandonments and drive pipe pre-installation operations. The company was prompted to design the Mastiff after the issuance of NTL5 in the US Gulf of Mexico last year, which requires operators to remove platforms that are no longer producing. Economics is extremely important for these operations because they bring no return on investment, Mr Harris said.

Lighter than a conventional rig, the Mastiff system can perform abandonments on old platforms that can’t take heavy loads due to rust or corrosion, saving operators the expense of a platform upgrade, Paul Adams, manager of plug and abandon operations for tubular services at Baker Hughes, said. It can also be rigged up in less than two days. “During a functional acceptance test, we put the derrick up in an hour and a half from the ground to the crown,” he said.

Further costs are saved because a rig is not required to deploy the system. “Anything you can do offline without a drilling rig saves the customers money in the long run,” Mr Adams said. The API 4F-certified Mastiff has been through a function acceptance test and is expected to mobilize for trials in Q4 this year.

The Mastiff isn’t limited to abandonment work. It can perform various operations such as tubing change-outs through coiled-tubing intervention. “We have the capabilities for a section that will fit a coiled-tubing injector head so that coil can rig up and run right through the Mastiff,” Mr Adams said. “Pretty much any well intervention type work can be accomplished with this unit.”

For continued field development, the Mastiff can initiate a slot recovery program prior to a drilling rig’s arrival. Once the pipe is removed, the well slot can be prepared for a new wellbore, saving rig time and offering the operator the option to further redevelop resources.

The ultimate goal of the system is not only cost savings, however, but safety, Mr Harris said. Because it is self-erecting, he explained, “we don’t have to send people up on riding belts to do the assembly. It’s all automatic once it starts.”

RELATED ARTICLE:

Enhanced intelligent well system reduces need for well intervention

Helix Well Ops expands well intervention fleet for Europe, Africa

Superior Energy Services’ HAWC tool features retrievable solutions, isolation methods, alternate production means and integrity enhancement specifications.

Superior Energy Services (SES) has introduced a new generation of its Hydraulic Actuated Well Completion (HAWC) system, an intelligent well (IW) technology with an on/off feature that allows one zone to be shut off while work continues on another zone. Tool features include retrievable solutions, isolation methods, alternate production means and integrity enhancement specifications. The system can help operators complete, produce and remotely control multiple zones without well intervention. Earlier this year, Anadarko Petroleum Corp awarded contracts to SES to implement the HAWC system for several Gulf of Mexico (GOM) completions.

More than 70 deployments of previous-generation intelligence systems led to the development of the new HAWC system, said Dewayne Turner, development manager for Superior’s Completion Tools. Comprised of at least two remotely operated hydraulic sliding sleeves and a retrievable hydraulic set-in-string packer, the enhanced system is deployed as part of the production string and works in conjunction with the SES sand face equipment that is installed adjacent to perforation intervals, Mr  Turner explained.

“The packer has been certified to American Petroleum Institute (API) standards at 350°F and 12,500 psi, and incorporates a pressure-assist feature that ensures system integrity during the life cycle of the well.” The packer also can be configured with several release choices, including shear release for shallow water and cut-to-release for deepwater, with internal/external release option. The design also provides the flexibility to pass through multiple control lines through the packer as needed.

The system uses a unique anti-vibration connector that is testable and incorporates a triple ferrule, yielding all-metal-to-metal seals. The internal sleeves are keyed to align the inner flow slots with the external body slots to minimize erosion. A proprietary seal stack on the sleeves minimizes shifting forces, prevents production entrainment and enhances seal longevity due to wellbore pressure differentials during cycling of the sleeves for production.

Intervention Costs Reduced

“Conventional sand control is performed on roughly 30% of the wells completed worldwide,” Mr Turner said. “Of those, very few are done in deepwater. This technology is suited for all selectively produced completions. In deepwater, intervention for such completions are extremely cost-prohibitive and thereby provide a platform for the application of IW technology. Ultimately, our HAWC system eliminates intervention costs and maximizes production potential through optimal reservoir management by the operator,” Mr Turner said.

SES sand face systems incorporate pressure-actuated production initiation technology valves, which eliminate the need to mobilize slick line or coiled tubing. “These sand face systems, when deployed in conjunction with the HAWC system above, form a truly intervention-less IW completion,” Mr Turner explained. “The intervention-less production initiation technology comprises various hydraulically actuated fluid loss control/production devices.”

Designed for both onshore and offshore applications, the system is suitable for GOM wells with wet trees that are typically placed far away from the platform, anywhere from 2,000 ft to several miles, Mr Turner noted. “Production is achieved by hydraulically actuating the zonal production sleeves,” he said. “Production is then managed and selected remotely by operating the HAWC sliding sleeves.”

The technology has allowed one operator to complete some wells while initiating production on other subsea wells, switching to the most productive zones to maximize production and keeping the platform productive for the life of those wells, Mr Turner said.

HAWC is a trademarked term of Superior Energy Services

Expanding its European and African well intervention fleet, Helix Well Ops UK will take control of the mono-hull well intervention vessel Skandi Constructor for three years, starting in spring 2013.

Helix Well Ops UK, a business unit of Helix Energy Solutions Group, is expanding its European and African well intervention fleet with a three-year charter of the mono-hull well intervention vessel Skandi Constructor, starting in spring 2013. The company’s current fleet is made up of the 132-meter (433-ft) long Well Enhancer and the 114-meter (374-ft) long MSV Seawell. Well Ops will build and test a specially designed version of its 7 ⅜-in. subsea intervention lubricator (SIL) to enable subsea well interventions to be undertaken from the Skandi Constructor.

The SIL is a single-trip well intervention system that provides well access while managing containment when the well is “live” and under pressure. The SIL is configured to undertake work through all types of subsea Christmas trees. The vessel and SIL will allow Helix Well Ops to provide its regional clients with a solution for deeper water wells and well interventions.

Launched in 2009, the Skandi Constructor is a 120-meter (393-ft) long Ulstein SX121 DP3 mono-hull well intervention vessel that features the new X-bow design. The 8,500-tonne vessel accommodates up to 100 personnel and is capable of working in depths of up to 3,000 meters (9,842 ft). It has a deck capacity of 1,470 sq meters (15,822 sq ft) and features an 8m x 8m (27 ft x 27 ft) moonpool, a 150-tonne crane, a multipurpose tower with 140-tonne lift capability and two work-class ROVs.

The need for a third vessel in the company’s fleet has been driven by operator requirements, according to Helix. The firm recently secured contracts from several major North Sea operators to provide light well intervention and associated subsea services from its existing vessels between 2013 and 2015.

Demand also has been strong from West Africa, the company said. The Well Enhancer was deployed to the region earlier this year, where it completed what was believed to have been the region’s first well intervention project from a monohull vessel.

Steve Nairn, regional VP of Europe and Africa for Helix Well Ops, said, “Well Ops is extremely proud to announce the addition of a third vessel to our fleet, and it underlines our commitment to providing well intervention services. Skandi Constructor strengthens our offering internationally and expands our well intervention service capability.”

It’s expected that the company’s investment will lead to the creation of 60 jobs – 50 offshore and 10 onshore – over the next nine months. Helix Well Ops currently employs 70 people in Aberdeen and a further 300 offshore.

The system uses a proprietary wellbore stabilizer that mechanically maintains wellbore integrity. By delivering a more stable wellbore in long horizontal sections, pore pressure transmission is reduced, minimizing or even eliminating mud losses. Drilling efficiency also can be improved with specially purposed lubricants that coat metal surfaces, drill cuttings and formation walls to reduce torque and drag, particularly in high-pressure, high-temperature applications. The lubricants also allow for the delivery of greater amounts of hydraulic horsepower to the drill bit and result in faster rates of penetration.

Because the system is water-based, disposal of oily cuttings is unnecessary, and cleanup time on the rig can be reduced by as much as two days compared with that of oil-based systems.

A pipe-cutting tool is one of several intervention devices in Welltec’s family of robotic tools.

Many oil and gas wells are “smarter,” with more automated monitor and control capabilities than ever, but regardless of how much state-of-the-art technology is placed downhole, even the most intelligent well eventually will need an intervention as a result of equipment failure, scale or sand build-up or integrity problems with tubulars. That’s where robotics comes into the picture.

A relatively new class of services, robotic solutions incorporate downhole mechanical, hydraulic and electric technologies to fix problems and restore production in automated wellbore completions, explained Brian Schwanitz, vice president of Welltec. Welltec is presenting a session, “Improved Downhole Robotic Technologies for the Oil and Gas Industry,” at the SPE well construction automation workshop on 16-18 July in Vail, Colo.

The tools are designed to provide remediation in wells that are scaled up or filled with sand from the formation or for mechanical problems with the casing or “jewelry,” such as valves or gauges that are permanently in the well. “Over the life of the well, these devices become disabled and won’t work anymore,” said Mr Schwanitz, who is also chairman of the Intervention and Coiled Tubing Association. “For example, if a downhole valve in an intelligent well stops opening or closing on command from the surface, a robotic tool can go in, latch into a shifting sleeve and perform a sequence that mechanically opens or closes that valve or even puts it into the correct partially opened (choked) position.

“Smart-well hardware is sophisticated, but complex, and with complexity comes a higher risk of failure,” he continued. “As these wells become more complicated, there needs to be more intelligence applied in the way problems are remediated. This is where new automation such as robotics is providing ‘intelligent interventions,’ with remote monitor and control, to catch up with what the industry is putting in the ground.”

Scale build-up in automated wellbores can be removed with a robotic milling tool.

Faster, cost-effective

Robotics offers “lighter touch” methods to adjust the flow by cleaning or cycling disabled valves, and monitoring the well. Most recently, diagnostic sensors have been deployed with the robotics to determine production or injection problems, and have expanded to include fiber optics and micro-seismic sensing. The technology provides a faster, more cost-effective alternative to restore production, especially in horizontal wells or offshore subsea wells, the two most challenging well intervention categories, he noted. Conventional remediation methods, such as coiled or threaded tubing and drill pipe, intervene in a blind mode and are expensive and time-consuming because they involve bringing in large amounts of equipment and people, which increases risk.

The relatively small tools are run into the hole on an electric wireline and can be controlled from the surface, as far as four to five miles away. Often, they are programmed in advance to do certain tasks. In long horizontal wells, the tools are run in on a tractor to clean out debris, remove scale deposits and bring debris back to surface without circulating fluids from the surface or using pumping equipment or a rig. For subsea wells, robotics tools can clean leaking safety valves or remove and replace a problem gas-lift valve from a small intervention boat, versus mobilizing a large semisubmersible rig at a cost of millions of dollars.

Since Welltec introduced downhole robotics to the market 16 years ago, the technology has finally achieved widespread industry acceptance and is now used in every operating province, Mr Schwanitz said. “Operators and service companies are now realizing that if they are going to design an intelligent completion in a well, they need to design it for intelligent interventions as well.”

In best cases, completions are being designed with failure contingencies from the beginning, instead of after something goes awry. “Robotics is one piece of the automation puzzle that is continuing to evolve,” he said. “As an industry, we need to keep these wells flowing for many years, and therefore, they have to be made intervention-friendly.”