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High-Pressure/High-Temperature BOP Equipment Becoming a Reality

Trent Jacobs, JPT Technology Writer

The offshore industry has taken another step toward opening up new deepwater frontiers to exploration with Maersk Drilling ordering the first 20,000-psi blowout preventer (BOP) made by GE Oil and Gas. The BOP is expected to be delivered in the first half of 2018 and is part of a multiyear collaboration between Maersk and BP to design a new generation of offshore drilling rigs for deepwater basins dubbed “20K Rigs.”

The ultimate goal is to enable the development of high-pressure/high-temperature reservoirs with pressures up to 20,000 psi and temperatures as high as 350°F. The technical limit of the highest-rated BOPs in operation today is 15,000 psi and 250°F. BP believes that with the 20,000-psi BOPs, and other technologies in development, it will be able to develop fields that may add an additional 10 billion to 20 billion BOE across its portfolio.

“GE’s new deepwater BOP system is a key part of Maersk and BP’s strategy to safely expand offshore field development into previously unexplored areas,” said Claus Hemmingsen, chief executive officer (CEO) of Maersk Drilling. “With its redesigned components, GE’s new BOP technology addresses the needs of drilling companies for BOPs that efficiently operate at extremely high pressures.”

GE is designing, testing, and building the 20,000-psi BOP and risers at its Houston Technology Center in Texas. However, the company said it is drawing on expertise from its global base of experts. The BOP will be rated for depths down to 12,500 ft and features upgraded rams designed for the higher pressures and extreme temperatures. It will also come installed with GE’s latest BOP control system and newly unveiled BOP monitoring and advisement software.

“The 20,000-psi drilling system being developed will include a number of new real-time monitoring and condition-based maintenance technologies aimed at improving uptime by reducing unplanned maintenance,” said Andrew Way, president and CEO of the drilling and surface business at GE Oil and Gas. “From higher-performance mechanicals to real-time monitoring and condition-based maintenance systems, this next-generation system can make accessible new offshore drilling ­frontiers.”


Refracturing Success Demands a Better Understanding of Past Failures

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

Refracturing older unconventional wells is likely to reward those willing to investigate the reasons why production declines and what can be done to restore it, according to George King, distinguished engineering adviser at Apache Corp.

King talked about what has been learned from refracturing wells, and why companies need to invest in answering the questions that remain unanswered in this young branch of the exploration and production (E&P) business. “We are going to have to look for better ways of fracturing initially and refracturing these wells,” he said during a webcast, which can be found under online events at SPE.org.

The immediate reward would be finding the best method for identifying wells apt to respond to treatment and developing cost-effective techniques to deliver it. Longer term, what is learned from the shortcoming of old wells can be used to improve the performance of new wells.

Past experience with refracturing has demonstrated the value of correcting past mistakes. A look at 13 wells refractured in the Barnett Shale in north Texas found on average that they returned to their initial production rate and added from 0.5 to 1 Bcf to their estimated ultimate recovery, King said. Devon Energy’s  paper (SPE 154669) on the wells put the average cost of the restimulations at USD 900,000.

Early refracturing projects were designed to correct the errors made during the trial-and-error process used to develop the techniques now commonly used to exploit shale formations. Many were vertical wells with only two stages for hydraulic fracturing. The gelled fluids used then damaged the formations and created relatively short fractures.

When Devon refractured those 13 wells, it expanded the number of stages to three, used more sand to prop open the fractures, and pumped slickwater to create larger more complex fractures using a fluid formula with a minimum of chemicals. The paper said: “Initial results were mixed, but the economics have gradually improved by developing candidate selection criteria, and modifying the simulation design to contain costs.”

That comment can serve as a summary for refracturing work since then. Results are mixed and good well selection is a major determinant of success and  cost-effective methods for diagnosing and addressing problems are critical. Adding to the challenges has been the industry’s rapid shift to liquids-rich fields using horizontal wells, many more stages, and improved methods based on years of experience.

The combination of liquids-rich plays, such as the Bakken and Eagle Ford and changing completion techniques, raise new  issues for the industry, King said. Refracturing interest in those plays is growing as wells reach the age where production has declined to the level at which refracturing becomes an option.

Based on past experience, success will depend on the wells chosen and the ability of companies to identify problems that can be economically remedied. While production from most shale wells declines steeply, the reasons for that vary. Understanding the root cause for lost output can mean the difference between success and failure when trying to revive an old well.

Refracturing a well where the problems are due to the rock is not going to pay off. Often a failure in refracturing indicates “there was not enough work on how much of the reserves are left to be recovered,” King said.

Geologic problems could be blamed on sections of the reservoir isolated by a fault, rock lacking adequate conductivity, or production lost to another well nearby, he said.  Problems in the ground that limit production are common. He pointed out that in many wells with regularly spaced fractures, only 50% of wellbore was contributing. “We are wasting a lot of energy and money fracturing all of the wellbore when some of it didn’t have much potential to begin with,” King said.

Where reservoirs are productive, analyzing the output over time can be useful. King said a change in the ratio of gas to oil production over time can be an indicator of changes in the well. A rising gas/oil ratio can indicate the fracture network is shrinking, providing enough space for natural gas flow but not for oil production.

Generally speaking, the problem can be treated by using hydraulic pressure to reopen fracture networks and pump in stronger, long-lasting proppant.  But when it comes to the details on how to do so, practical advice is limited. Little has been written evaluating successful refracturing projects and even less analyzing failures, King said.

King was peppered by questioners with practical concerns: what is the best method to use for fluid diversion techniques, how to pressure test old wellbores to ensure that they can stand up to refracturing, and whether to use current perforations or create new ones. He offered thoughts on that wide range of topics, but warned that many questions have yet to be answered.

A company considering a significant refracturing program on the order of 100 wells should consider creating a team of professionals, King said. “The learnings from that would cover cost many times over,” he said.

There are wells where a refracturing job would stand out as a technical achievement. “With refracturing, you are at the mercy of what is in the well,” King said. “The first completion is going to be the easiest. Redos are going to be more difficult requiring some thought and probably development of new tools.”

As companies become more interested in going back into wells, it could alter the decision-making process when completing new wells.  “The best completion is the one that gives you the best flexibility with refracturing,” King said. That line of thinking can offer support for wider diameter casing and plug-and-perf completions.

And it may be wise to start with relatively modest steps. King suggested using coiled tubing to deliver a relatively low level of hydraulic pressure to clear out near wellbore obstructions, and a straddle packer to isolate the zone while doing so.

“Try putting a straddle packer on coiled tubing and go to each perforation cluster and hydraulically fracture it using high-quality proppant,” King said to listeners on the webcast, adding, “the few I have seen that have not worked all that well may indicate a reservoir problem rather than a completion ­problem.”

The SPE Webinar:

http://eo2.commpartners.com/users/spe/session.php?id=13200
“Refracturing: Timing, Prerequisites, Diversion and Application”
by George King.

For Further Reading

SPE 134330 Refracs: Why Do They Work, and Why Do They Fail in 100 Published Field Studies? by Mike C. Vincent, Insight Consulting.

SPE 154669 Barnett Shale Horizontal Restimulations: A Case Study of 13 Wells by Mark Craig and Steven Wendte, Devon Energy, and James Buchwalter, Gemini Solutions.

SPE 168607 Refracturing Horizontal Shale Wells: Case History of a Woodford Shale Pilot Project by S. French, J. Rodgerson, and C. Feik, BP America Production Company.


US Approves BP’s use of Unmanned Aerial Vehicles in Alaska

Trent Jacobs, JPT Technology Writer

In June, the United States Federal Aviation Administration (FAA) issued the first approval for the overland use of unmanned aerial vehicles (UAVs) in Alaska. The authorization was granted to BP and UAV maker AeroVironment for aerial surveys of roads and pipelines in Alaska’s prolific North Slope oil fields. Last year, the FAA issued a more restrictive approval to BP and ConocoPhillips that allowed the companies to fly UAVs over Arctic waters, and only during optimal conditions.

BP and AeroVironment carried out the first approved flight on 8 June, using a Puma AE, a hand-launched vehicle that is 4.5 ft long with a 9 ft wingspan. BP intends to use the lightweight UAV for “high-accuracy” land surveys and for map making to identify maintenance requirements on roads and infrastructure. “The (unmanned aerial system) technology has potential to improve safety, efficiency, and the reliability of BP’s Alaska North Slope infrastructure and maintenance programs,” said Dawn Patience, a BP spokesperson.

For AeroVironment, the largest maker of UAVs for the US military, the latest approval offers the company a chance to demonstrate the benefits of the technology to both private companies that want to use the technology and the government, which is tasked with regulating it. “It is an important first step in introducing the capabilities that small unmanned aircrafts deliver for a large number of commercial applications,” said Steve Gitlin, vice president of marketing and communications for AeroVironment.

Gitlin added that the process that BP and AeroVironment followed to obtain approval was very similar to the process commercial airline companies follow to be granted restricted licenses. “From that perspective it is ground breaking,” he said. “Our hope is that this is the first of many (approvals) to come.”

Earlier this year, the FAA announced the selection of sites in Alaska, Nevada, New York, North Dakota, Texas, and Virginia where UAV testing and research will be used to help the agency integrate the technology into the US airspace. Establishing testing sites was part of a 2012 law passed by the US Congress that also ordered the FAA to permanently allow for the use of small UAVs in Alaska’s Arctic areas. “These surveys on Alaska’s North Slope are another important step toward broader commercial use of unmanned aircraft,” said Anthony Foxx, US transportation secretary, who oversees the FAA. “The technology is quickly changing and the opportunities are growing.”


BHP Billiton Testing New Methods To Maximize Returns on Completions

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

Running a shale exploration and production operation requires a sharp focus on costs, but not all are measured the same. BHP Billiton’s method for evaluating the cost of drilling an unconventional well is different from the one used to gauge the cost of completing one.

The difference reflects the potential production upside of spending more to fracture formations more effectively compared with drilling. BHP is seeking ways to create more productive fracture networks by manipulating the stresses in the rock between wells, and seeking efficient ways to go back into older wells without the cost of the hardware needed for the initial fracturing work.

“Productivity improvement is something we are relentless about at the moment,” said Rod Skaufel, president of North American shale at BHP, during a recent company briefing in Houston.

He said the Australian mining and energy company realized about a year after acquiring onshore assets in the US that the management methods used for offshore development were not going to work when mass producing wells onshore. There was a wide gap between its cost to drill a well and what competitors were paying for comparable work. Over the past six quarters, it has recorded a 26% increase in drilling efficiency, said Skaufel, adding that BHP is “one of the fastest drillers in the Eagle Ford.”

When it comes to completing  shale wells, the productivity measure shifts from a comparison of the cost-per-foot to drill to calculating the return on investment based on long-term production. BHP’s challenge is maximizing the return on USD 4 billion annual budget for US shale operations, which is not expected to change much this decade, and a staff that has grown to 2,000. Those resources must be allocated over four plays that could absorb more money and staff time than the company has available.

For now, BHP’s development focus is the Eagle Ford Shale, with 17 of its 25 rigs drilling in the South Texas play. The rest of the rigs is split between the Permian Basin and the Haynesville plays in Texas, where it is doing detailed studies to improve its results when it increases activity in the future. BHP is also in the Fayetteville Shale.

When completing wells, BHP is looking for ways to modify how it uses the current tools to deliver more sand to prop open fractures, and is testing new options. The company concluded that it could increase the output of its wells by 20% to 60% by delivering more proppant in fractures to hold them open, Skaufel said. To do so, it is using more viscous fluid mixes able to transport more sand and larger percentages of finer sand (100 mesh), which is less likely to settle out during fracturing and can fit into smaller fissures.

Planning and research efforts are considering how to space wells to maximize their output over the 2-year time frame it uses to evaluate wells. One pilot is testing a three-well pattern designed to encourage more complex fracture networks, which could mean a greater output using an idea from the University of Texas at Austin.

The goal is to change the natural stress patterns in the rock among three parallel wells so that when a hydraulic force is applied, the cracks created form complex patterns. Two horizontal wells on the outer edge are fractured, creating stress shadows that are expected to cause more complex, productive fractures when the third well is fractured.

“We fracture from the outside in to create in-situ stress,” Skaufel said. It requires spacing the wells close enough to allow overlapping stress and limiting the fracture length to avoid overlapping fractures. The measure of success will be long-term production. While there is a lot of attention paid to initial production rates during the first 100 days of output, he said that longer-term production studies show that the wells with the highest early output tend to trail after 2 years.

The company is also looking for a method to cost-effectively refracture older wells. BHP is partnering with Schlumberger to work on ways to use its BroadBand chemical treatment to allow the operator to target specific spots in a well without having to physically isolate those areas using bridge plugs.

BHP is taking its time in the Permian Basin where the exploration challenge is picking which of the many options will offer it the best return.  Although its Black Hawk play in the Eagle Ford appears to offer the most productive rock, the Permian offers many more options. Beneath leases covering 450,000 acres, there are three horizons, each containing another three potential zones, to develop, he said.

In the Haynesville Shale, four rigs are working as BHP seeks the best development option. While gas prices have risen to nearly USD 5 per Mcf, its formula for choosing which wells to develop based on future price trends favors liquids-rich basins over gas producers by a wide margin. For now, the company is looking for the most effective way to space wells and complete them in the Haynesville, preparing for the day when full-scale development resumes. “Gas is not going anywhere we have time,” Skaufel said.


Saudi Aramco Wants Fields Fully Smart by 2017

Abdelghani Henni, JPT Middle East Editor

Saudi Aramco’s new strategy aims to implement its intelligent field (I-Field) concept in all its upstream operations by 2016-2017, according to a source close to the company.

The move is part of the company’s efforts to be more proactive in field management and move toward a vision of autonomous fields. “All of Saudi Aramco’s fields are set to be intelligent by 2016-2017,” the source said.

Saudi Aramco is considered one of the leading national oil companies to adopt a smart field initiative through the I-Field concept, which integrates real-time data in its upstream business processes. It currently has 19 I-Fields underway.

The deployment of the I-Field concept at Saudi Aramco’s fields has enabled the company to more closely monitor reservoirs. “For the reservoir, if something happens, we can correct it in six months, but … some of the damages are irreversible damages,” the source said. “Now, with real-time reservoir monitoring, we can correct the damage earlier.”

The involvement of Saudi Aramco with the intelligent field concept started with the development of the Haradh III project. “That was the industry’s most sophisticated smart field development, with multilateral wells, all equipped with smart completion, and real-time data which can control any well, any time,” the source said.

The field development, occurring over a decade, offered a unique opportunity to gauge the impact of technologies. Haradh I was developed exclusively with vertical wells, whereas horizontal completions provided the primary configuration for producers/injectors in Haradh II. Haradh III was developed by relying mainly on smart completions within an I-Field framework. The total Haradh production capacity is 900,000 BOPD, with equal contributions from the three subsegments.

The Haradh III development at the southern tip of the Ghawar oil field in Saudi Arabia, completed in 2006, has been portrayed by Saudi Aramco as the turning point in the battle between geological adversity and engineering prowess. The poorest reservoir rock in Ghawar has succumbed to the latest in well and drilling technology. Aided by 3D seismic images showing fracture locations, well sites were optimized and drills were guided by remote control from Dhahran. Smart completions were standard, and an I-Field was set up.

Maximum-reservoir-connectivity wells (MRCs) were fitted with monitoring electronics and valves on individual laterals so that they could be throttled back as needed to minimize water encroachment. After testing and adjustments, everything rolled out ahead of schedule. Goals for individual well productivity of 10,000 BOPD were met, and projections indicated smooth sailing for 10 years or more.

Haradh III became the first Saudi Aramco development project to be developed exclusively with MRC wells with downhole ICVs for flow control. Average well-production rates were ­targeted to be 10,000 BOPD, compared with 3,000 BOPD and 6,000 BOPD for Haradh I and II, respectively. The smart completions were necessary to ensure production sustainability in the face of premature water encroachment through fault/fracture systems. In fact, the well requirements and relative unit costs would have been considerably higher had vertical or conventional single-­horizontal wells been selected instead of MRC wells for Haradh III.

“After the Haradh field development, all the increments, with no exception, became smart fields, including Abqiq and Khurais,” the source said. Khurais is the largest increment in the world, with production capacity of 1.2 million BOPD. “In the Manifa field, we are getting the data of the pressure before we put the wells in production.”

While implementing an I-Field is easy with green fields, brown fields are more challenging. In the southern reservoir area, which includes brown fields like Ghawar, Khurais, and Abqiq, establishing an I-Field requires a strategic surveillance program.


Saudi Aramco Aims to Slash Costs

Abdelghani Henni, JPT Middle East Editor

Saudi Aramco is working on slashing the production cost of tight formations to around USD 2 to USD 3 per thousand cubic feet in the next couple of years, according Adnan Kanaan, manager of the Gas Reservoir Management Department (GRMD) at Saudi Aramco.

Kanaan said that his company  expects to reach its target that may lead to a break-even cost that would equal the best unconventional plays in the US. “We are seeing good signs from the sandstones and good costs in our drilling and completions,” Kanaan said during the 21st World Petroleum Congress held recently in Moscow.

The company has conducted work on tight sands reservoirs where permeability and porosity is greater than that of shale formations but below that of conventional oil and gas bearing sands. “We do have shale, but shale will take a little bit more time because we need to go with the low-risk, high-reward projects to get our revenue,” Kanaan said. “But definitely shale is part of our focus area, and it is part of the exploration and appraisal.”

In recent years, Saudi Aramco has made significant progress with its unconventional resources, where it started making allocations for industrial projects in Saudi Arabia, the company said in its 2013 annual review.

The company said its unconventional gas program became fully operational in 2013, only two years after launching its own unconventional gas program in the frontier Northern Region, offering new resources for the country’s energy needs. The company said that it is ready to commit shale gas for the development of a 1,000-megawatt power plant that will feed a massive phosphate mining and manufacturing sector. “Saudi Arabia will be among the first countries outside North America to use shale gas for domestic power generation,” the company said.

It has also made significant progress in developing hydraulic fracturing technologies as part of its efforts to push for new and better ways to conduct fracturing operations with the least environmental impact possible.