| day 4 chevron’s goal: rein in the year supply chain midfielders...

BY RHONDA DUEY

At an OTC panel discussion Tuesday afternoon about Mexico’s energy reform, no one denied that the mea-

sure was a good idea. But they were not shy about iterat-ing the challenges it would present to the service sector. After 75 years of having a single customer, PEMEX, service companies will have to adjust their mindset to accommodate an increasing cast of characters.

“Future growth depends on efficient implementation of the energy reform,” said Iain Cook, vice president, Secure Drilling Systems for Weatherford.

No doubt there’s work to be done. The U.S. portion of the Gulf of Mexico has more wells in deepwater alone than Mexico has in its entire offshore region. This will result, Cook said, in increased service intensity and addi-

BY DARREN BARBEE

The recent shock of English football—Leicester City winning the English Premier League despite 5,000-

to-1 odds stacked against it—shows how far focus can take a team.

Chevron Corp. is arguably at the top of its league in the Gulf of Mexico, where it is the largest leaseholder and produces 140,000 bbl/d.

Yet the company sees gaps between where it is and the goal line and cannot help but fret.

“Bluntly, we’re finding it too often where we don’t have the necessary competencies, the technical competency, to do the engineering that we need to do to complete these projects,” said Mick Kraly, Chevron’s general manager of facilities engineering. Kraly spoke Tuesday at an OTC luncheon.

Large projects have become immensely complex, with engineering, inspections, fabrication, construction, precommissioning and startup demonstrating a “lack

of depth in the competencies we really need.”

But Kraly sees parallels to Leices-ter City as the model for thriving.

As Chevron and other deepwater operators push farther and deeper into the water to reach areas of opti-mal return, an unbalanced stack of concerns have built up like paperwork

on an untidy desk. Suppliers, engineering and safety con-cerns only grow as new technology—while ultimately valu-able—can lead to optimism that may blind operators to risk.

“A lot of our projects now are bigger, larger and harder to reach,” Kraly said, with more complicated supply changes making Chevron “rethink things.”

While Chevron’s brownfield projects have sin-gle-well breakevens typically in the $20 to $40 Brent

BY JOSEPH MARKMAN

Got patience? Good, because 2016 embraces a trend of

deferred projects in the deepwa-ter sector.

“Investors are rewarding deep cost-cutting and tighter capital discipline,” Julie Wilson, research director for global exploration at Wood Mackenzie, told a break-fast crowd on Wednesday at OTC.

“The stars really have to align for a project to go ahead.”Though her talk came with the less-than-cheery title

of “Deepwater Exploration and Development: Creat-ing Value has Rarely Been Tougher,” Wilson expressed hope for a strong recovery in the not-too-distant future.

“Right now we’re pretty optimistic for 2017 and 2018,” she said. “But will we be ready? Will oil prices be where they need to be?”

At the moment, they definitely are not. 2016 will be challenging, Wilson said, with few

projects moving forward and as much as 4 Bbbl of oil at significant risk of being pushed back. Major cap-ital-intensive projects have been hit hard, and final investment decisions on 29 greenfield deepwater proj-ects have been deferred, by Wood Mackenzie’s count.

“Although we’ve got no shortage of discovered resources, we’re not moving forward,” she said.

Annual exploration and appraisal spending in deep-water, which tripled from $15 billion to $45 billion between 2006 and 2013, has fallen off. Much of that burst of spending was sunk into frontier projects, and the total number of wells during that time only rose by 14%.

Many frontier projects are simply not worth pursu-ing. While reserves of 100 MMbbl to 200 MMbbl are viable in some areas, the lack of existing infrastructure on the frontier kills the economics.

And the funds available for those projects have dried up.“It’s a pretty grim picture for capex,” Wilson said.Wilson recommends that her clients consider rede-

signing a project and perhaps reducing its scope. She

See GOAL continued on page 21

| THE OFFICIAL 2016 OFFSHORE TECHNOLOGY CONFERENCE NEWSPAPER | DAY 4

2016.otcnet.org Thursday, May 5 | Houston, Texas

Chevron’s Goal: Rein in Supply Chain Midfielders n Even deepwater drilling executives get the blues: too often even the majors lack the core competencies required to get projects right, facilities engineering manager says.

Surviving Reform: Service Companies Face Challengesn With an influx of new customers in Mexico, contractors will need to adapt to a new landscape.

The Year of Drilling Sluggishlyn Recovery is on the way, Wood Mac exploration expert says, but many promising projects will be delayed until it arrives.

See CHALLENGES continued on page 21 See DRILLING continued on page 23

Julie Wilson

Mick Kraly

3OTC SHOW DAILY | MAY 5, 2016 | THURSDAY

SCHEDULEOF EVENTS

All events in conjunction with OTC 2016 will be held at NRG Park in Houston, Texas, unless noted otherwise.

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Thursday, May 5

7:30 a.m. to 2 p.m. ..................................Registration

7:30 a.m. to 9 a.m. .................................. Topical/Industry Breakfasts

9 a.m. to 2 p.m. ......................................Exhibition

9 a.m. to 5 p.m. ......................................University R&D Showcase

9:30 a.m. to 12 p.m. ................................Technical Sessions

12:15 p.m. to 1:45 p.m. ........................... Topical Luncheons

2 p.m. to 4:30 p.m. .................................. Technical Sessions

4 p.m. to 5 p.m. ......................................OTC Closing Reception

Friday, May 6

7 a.m. to 4:30 p.m. ..................................d5 at Rice University

Editorial DirectorPeggy Williams

E&P Group Managing EditorJo Ann Davy

Editor-In-ChiefMark Thomas

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d5 at Rice University d5 is an OTC event designed to spark creativity and innovation in the offshore energy industry. d5 will bring together the brightest minds across multiple industries for talks that inspire participants to discover unique con-nections and solutions. The event is scheduled for 7:30 a.m. on Friday, May 6, at Rice University in Houston.

Speakers include:

VIVEK WADHWA (keynote speaker)

Wadhwa is an academic, researcher, writer and entre-preneur who focuses on exponentially growing tech-nologies that are soon going to change our world.

HELEN GREINER

Greiner is co-founder of iRobot, which develops robots for the industrial, consumer and military markets, and CEO of multirotor drone developer CyPhyWorks.

DEREK MATHIESONMathieson is vice president, CTO and marketing officer of Baker Hughes Inc.

RAM SHENOY Shenoy is the former ConocoPhillips CTO and cur-rent principal at Innovation Impact LLC.

LARRY TESLER

Tesler is a Silicon Valley consultant who has led in-novation in user-centered computing for more than 50 years at places like Stanford, Xerox PARC, Apple, Amazon and Yahoo!

GINDI VINCENTVincent is an author, speaker, blogger and counsel at Exxon Mobil Corp., who writes and speaks nation-ally on brave leadership.

JUDSON JACOBSJacobs is senior director with IHS Energy, leading its upstream technology practice.

Space is limited so reserve your ticket today. Event purchase includes breakfast, lunch and the reception. Tickets are $495. Attire is busi-ness casual.

OTC 2016 attendees enjoyed lunch and networking outdoors during the annual conference that drew tens of thousands of visitors to Houston. (Photo by CorporateEventImages.com)

CONTRIBUTED BY FLUOR

Generally, subsea facilities including pipelines, flow-lines and umbilicals cannot be shown to have the

capacity to survive direct contact with ice features.Pipelines installed in Arctic regions are therefore

generally trenched to a predetermined depth below the bottom of the design ice gouge incision depth. For pipelines, the amount of additional trench depth required below the design ice gouge incision depth is based on the amount of pipeline movement caused by the sub-gouge soil displacement beneath the keel of the ice features. Depending on the pipeline depth below the ice keel, this sub-gouge soil displacement can be

sufficient to bring the pipeline beyond its design bend-ing strain limits.

Similarly, subsea structures such as templates, manifolds and subsea trees must be installed at depths that ensure interaction with ice keels is avoided. Fluor has developed a patent-pending design to address the ability of drilling and production of subsea wells in shallow water that avoids ice and soil intrusions and allows a double containment envi-ronment to allow safe and reliable production of hydrocar-bons in the Arctic and ice infested environments.

Operability• Minimizes the consequences of loss of high-risk

components (i.e., subsea drilling and production

template, pipelines and control umbilical) and lim-its the number of common modes of failure.

• Provides entry points for ease of access for future drilling and repeatability of jackup rig setup.

• Allows configurations that can accept ROV/ diver access.

• Includes full-time monitoring and control from re-mote command and control facility onshore or host.

• Provides a seawater circulation sys-tem to prevent anaerobic bacteria and therefore mitigate corrosion issues from same within the enclosure.

• Provides a safety relief/purge system for any natural gas buildup within the enclosure in the event of an incident within the enclosure.

• Allows provision for future well work-over requirements to allow access and operability by special provision coil tubing well workover system during the winter.

Availability• Provides clearance and access to the

drilling and production template for a work class ROV with manipulators within the protective enclosure.

• Provides long-term submergence AUV/ROV with garages and subsea cameras, microphones and lights to provide available and backup response to service the drilling and production template wellheads and manifold.

Proven technology • Selected well-known manufacturing

techniques and field-proven hardware throughout the design.

• Selected existing connection technologies.• Selected installation methodologies. • Minimizes size and weight envelop of

subsea production hardware to maxi-mize use of lower spec vessels.

Manufacturability• System configured to be as simple as

possible without compromising func-tionality or operability.

The protection structure is sized to allow a working class ROV to maneuver within the enclosure to conduct operations and mainte-nance tasks as well as to support the drilling operations. For these reasons, sufficient space has been allowed to accommodate ROV and diver access to connecting the pipelines and control umbilical within the structural enclo-sure. Space also is provided for a ROV garage on the opposite side as the pipeline access.

Fluor is well-poised to deliver these shallow-water drilling and production protection structures for ice environment solutions given its extensive knowledge on subsea and deepwater, floater technolo-gies, proprietary technologies, fabrication capabilities, including the mega Zhuhai fabrication yard in China and similar facilities in Mexico, supply chain strength as well as engineering, procurement and construction management and engineer-ing, procurement, installation and con-struction capabilities. n

Protecting Facilities in Shallow-water Subsea Ice n New design addresses drilling and production challenges.

4 THURSDAY | MAY 5, 2016 | OTC SHOW DAILY

Fluor’s shallow-water drilling and production protection structures are suitable for subsea ice environments. (Image courtesy of Fluor)

CONTRIBUTED BY AFGLOBAL

Mitigating risk and improving the efficiency of drill-ing operations are crucial to the future of deepwater

drilling operations. Some of the most significant achieve-ments are coming from new technologies made possible by the growing use of closed loop drilling (CLD) systems.

This conversion of the rig’s circulating system unfolds a broad new set of capabilities for managing and mon-itoring pressure, from the fundamental safety of riser gas handling (RGH) to the wellbore finesse of man-aged-pressure drilling (MPD).

The change is transformational. By con-ducting a basic rig operation in a funda-mentally different way, the industry is enabling the technologies that will make future deepwater drilling possible. A key enabler of this change is a versatile riser gas technology that provides a fundamen-tal safety advance and is the first step to creating an MPD ready rig.

AFGlobal’s Riser Gas Handling system fully integrates with the marine riser and rig systems to create a CLD ready configuration. The immediate result is an effective way of mitigating riser gas that is easily installed as a retrofit and aboard new dynamically posi-tioned and moored rigs. Equally significant, the RGH system with its component design provides a flexible structure for integrating service company hardware and controls with the riser and the rig.

The component design also creates a path forward by facilitating upgrades to the RGH system as well as supporting the evolution of rig and service company technology. In this regard, it is a de facto standardization template for building MPD ready rigs, and advancing new MPD technologies. The RGH system provides drilling contractors with the technology to make their rig MPD ready and the service company with a standard for connecting proprietary equipment and controls.

An example is the recent upgrade of the RGH system’s drillstring isolation tool (DSIT). The tool is a riser joint component that is closed to strip pipe and mitigate swabbing and surging. On the rig, the DSIT Gen II’s modular design facilitates quick servicing of the annular element onboard the rig, reducing valuable nonproductive time. This tool is readily incorporated in the riser by exchanging the tool components.

The AFGlobal RGH system provides autonomous operation to control flow distribution without a rotating control device (RCD). The unique capability facilitates quick and efficient handling of incidental gas in the riser in a controlled manner before it becomes a problem on the rig floor.

The system provides conventional and CLD options that can be fully integrate into a rig’s existing riser. Importantly, it

does this while providing the flow capacity needed for MPD operations.

As a fully MPD scalable system, the RGH system works with all known MPD service provider’s equip-ment. In RGH applications, the system closes the loop with a hydraulically activated packing element housed in a specialized riser joint. The element is quickly closed around the drillpipe for annular diversion or opened for conventional drilling operations. The RGH system enables the addition of an RCD to facilitate MPD. A specialized adapter fully integrates the equipment with the riser.

RGH system components consist of a top and bottom riser interface, drillstring isolation tool and a valve system to dis-tribute flow to a de dicated manifold and integrated control system. The assembly enables diversion of the well flow to a mud gas separator, overboard lines, MPD manifold or any other destination designated by the rig operator or contractor.

A broad-based belief and adoption of the technology is evidenced by the numerous systems purchased by opera-tors, service companies and drilling contractors. The system has been successfully deployed in the Gulf of Mexico, Brazil and offshore West Africa. Great success has been achieved in both standard riser gas and MPD applications. n

RGH System at the Center of Deepwater Drilling’s Future n Significant achievements are coming from new technologies made possible by the growing use of closed loop drilling systems.


Great success has been achieved in both stan-dard riser gas and MPD applications.


BY RHONDA DUEY

Deepwater ocean-bottom node (OBN) systems have gone from a scarcely proven technology to a go-to

technology for imaging near structures and below salt. In a presentation Tuesday morning at OTC, David Hays, Jim Thompson and Michael Morris from FairfieldNodal dis-cussed a new concept in deepwater OBN—semipermanent reservoir monitoring. This has attractive advantages over a cabled permanent reservoir monitoring (PRM) solution.

The company has designed and built a node that has enough energy storage for five years on the seabed and 300 active recording days. This is enough for one base-line and 11 monitor surveys of about 25 days.

Fairfield also has designed a high-speed underwater optical communications system to perform data down-load in situ on the seafloor.

The nodes are deployed in “sleep” mode and can be remotely activated, first for a quality control (QC) check and then for active recording. Once the survey is com-plete, the communications system collects the data from each node and shuts it down without handling it but by approaching it with an ROV to make data transfer. The inspection class ROV need only to hover for a few minutes over each node to recover multicomponent data recorded over 25 days at a 2 ms sample rate. The surface vessel handling the ROVs also can be the source vessel for the survey.

The new nodes have about the same mass and form factor as current deepwater nodes, but they have reduced power consuming recording electronics, higher ener-gy-density battery chemistry and precision clock tech-nology with minimal drift and no stabilization wait time.

So far 10 prototype units have been built and laborato-ry-tested, and a sea trial in the Gulf of Mexico in 1,000 m (3,280 ft) was conducted alongside a conventional OBN operation. After the results are in, the team expects to make some design modifications and then go into com-mercial production.

The concept has potential application to replace PRM systems, of which only 13 operating systems exist world-wide. As the presenters noted, PRM systems are not just

another seismic experiment—they are large-scale engineering and facilities proj-ects with custom-designed components for particular fields. Their cables must be trenched alongside other subsea kit, and the upfront expense is very high.

A semipermanent nodal system is expected to cost significantly less than a conventional cabled PRM system, and there’s less risk to subsea equipment during installation.

Additional benefits include no pipeline crossings; no ties to production facilities, aiding with HSE and logistics; and no recording space required on production facilities. Deepwater OBNs have been deployed 30,000 times over the past 10 years with 98+% reliability, reducing main-tenance costs.

One of the biggest advantages for semi-permanet reservoir monitoring is the ability to reconfigure the nodes as more becomes understood about the reservoir.

There are some drawbacks, of course. PRM systems can pretty much provide seismic on demand, and companies like BP that have been using them for years report that obtaining a repeat survey has become very routine. Also, since data are not avail-able until all source points are complete, there will be about a week of onboard QC, shot positioning, timing analysis and data reorganization before final delivery. To overcome some of this, AUVs might be used to harvest the data to speed up the cycle time. n

Is Semipermanent Monitoring With Nodes a Reality? n New deepwater system offers benefits over PRM systems.

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BY EMILY MOSER

Deepwater exploration might have more in common with mankind’s voyage into “the final frontier” than

one might first imagine, according to David Kaplan, safety and mission assurance partnership development at NASA’s Johnson Space Center.

For example, both NASA and the oil and gas indus-try, specifically offshore, have experi-ence dealing with complex facilities, operated in hostile and isolated envi-ronments, Kaplan said during an OTC breakfast on Wednesday.

“Frankly, where a single mistake can have extreme consequences,” he added. Unfortunately, both groups are not strang-ers to tragedy.

From 2003 to 2010, the U.S. oil and gas industry, both onshore and offshore, had a collective fatality rate seven times higher than for all U.S. workers, according to a report by the Centers for Disease Control and Prevention released in 2013.

The industry’s volatility was most widely felt during the Deepwater Horizon oil spill in 2010 where an explosion on the rig caused by a blowout killed 11 crewmen.

For NASA, Kaplan said a weakening in safety culture eventually resulted in the Space Shuttle Columbia disaster in 2003, when the shuttle disintegrated as it reen-tered Earth’s atmosphere, killing all seven crew members.

Following the Columbia disas-ter, NASA aimed to never experience another tragedy of a similar magnitude again. The agency ended up adopting the probabilistic risk assessment (PRA) technique after a vigorous process exam-ining its safety culture.

“I don’t want to know when something bad happened,” Kaplan said. “I want to know when my eye has been taken off the proverbial ball.”

First developed by the nuclear indus-try, the PRA is used to quantitatively model risk.

NASA has used the technique in the modeling of the Space Shuttle Program. It’s also presently being used for the Interna-tional Space Station and Orion deep space capsule programs.

“[The PRA’s] critical focus is it does account for human error. We can access the reliability of humans in the overall flow and also accounted costs,” he said.

The oil and gas industry may soon fol-low in NASA’s footsteps following a five-year agreement in March between the agency and the Bureau of Safety and Envi-ronmental Enforcement (BSEE) to exam-ine risk offshore.

“NASA and BSEE are exploring the possibility that PRA may provide insight to the operator that will allow them to mitigate risks in a meaningful way,” Kaplan said.

The agreement between the two government agencies allows BSEE to capitalize on the best risk man-

Final Frontier: NASA to Share Risk Management with Offshore Industry n NASA and the BSEE announced a five-year agreement in March to examine risk offshore and further strengthen worker and environmental safety.

See NASA continued on page 21

David Kaplan, Safety and Mission Assurance Partnership Development, NASA, addressed attendees during Wednesday’s topical breakfast, “Risk Management at NASA and Its Applicability to the Offshore Industry.” Y Doreen Chin, Shell Exploration & Production Co., was session chairperson and moderator. (Photo by CorporateEventImages.com)

“I don’t want to know when something bad happened.”

—David Kaplan, NASA


BY JOHN SHEEHAN

Oil and gas producers in the U.K. North Sea increased output by more than 7% in 2015, the first

rise in 15 years.But the industry will be hard-pressed to sustain this

into 2016 in a lower-for-longer oil price world, Oil & Gas U.K.’s CEO Deirdre Michie has warned.

She said, “While the U.K. offshore oil and gas indus-try is having to adapt to the low oil price and drive greater efficiencies throughout its operations, the fact is that the value of our product has more than halved. Times are really tough for this industry and for the people working in it. We will continue to see job losses as we move into 2016.

“As we go through these times, we have to be resilient and focus on what we need to do to get us through the coming months to ensure an enduring industry for the future.”

Despite the gloom, however, there are a number of projects due to come onstream that will help keep the oil and gas flowing in the region.

Cladhan Field begins productionThere already has been some good news for the U.K. sector at the start of 2016, with Abu Dhabi National Energy

Co. (TAQA) bringing the Cladhan oil field northeast of Shetland onstream.

The field, which has been developed as a subsea tieback to the TAQA-operated Tern Alpha platform, is expected to pro-duce 10 Mbbl/d.

The Cladhan Field is located in the northern North Sea in a water depth of about 150 m (492 ft) and straddles U.K. Continental Shelf (UKCS) Blocks 210/29a and 210/30a. The development consists of two producer wells and one injection well.

Premier Oil’s Solan Field also is expected onstream imminently, although timing of startup is weather-dependent.

Solan is located in UKCS Block 205/26a in 135 m (443 ft) of water and is expected to produce about 40 MMbbl of oil at an initial rate of 24 Mbbl/d.

Two production wells and two water injectors have been tied back to a nor-mally unmanned processing deck sup-ported by a jacket.

Oil will be stored in a 45-m by 45-m by 25-m (148-ft by 148-ft by 82-ft) subsea tank prior to being offloaded to shuttle tankers. Premier said recent tanker trials have been successful, and commissioning work has continued.

Schiehallion, Loyal redevelopmentBP also will be busy in 2016 on its Quad 204 project, a redevelopment of the Schiehallion and Loyal fields, which will extend production out to 2035 and pos-sibly beyond.

The Glen Lyon FPSO vessel is cur-rently undergoing sea trials at the start of its journey from the Hyundai Heavy Industries yard in Korea to the west of Shetland, where it will serve as the hub for the 450-MMbbl Quad 204 development.

The project involves connecting and commissioning the new FPSO unit; the drilling of several new production and injection wells; and upgrading the subsea pipeline, manifold and wellhead infra-structure that will enable the full devel-opment of the reserves.

New subsea infrastructure includes five new production flowlines, one new dynamic umbilical, two new static umbili-cals, six new risers and two new manifolds.

Battle Ahead for UK North Sea n Oil & Gas U.K. warns of tough times ahead for the North Sea, but projects due to come onstream offer a glimmer of hope.

See BATTLE AHEAD continued on page 20

The Cladhan Field has been tied back to the Tern platform. (Photo courtesy of TAQA)


BY RHONDA DUEY

Good news might be a bit slim on the ground at OTC this year, but for anyone who’s looking for

a virtually unexplored region with tons of potential, Newfoundland and Labrador (NL) offers up consid-erable promise.

Jim Keating, vice president of oil and gas for Nalcor, addressed a crowd Wednesday morning at OTC about the area’s prospectivity. Let’s do the numbers: While the oil price has dropped 60% and offshore exploration worldwide has dropped a similar amount, NL has seen an increase of 600% in activity over the same period of time. A recent resource assessment determined that the first 11 blocks licensed have the potential for 12 Bbbl of oil and 33.9 Bcm (1.2 Tcf) of gas. And that’s the tip of the iceberg, representing less than 2% of the total area. Overall the region covers 1.8 million km (695,000 sq miles), of which 1 million km (386,000 sq miles) is sedimentary basins.

“It’s the size of two or three North Seas,” Keating said.

So where has this region been all of our lives? Keating showed a slide that indi-cated that in the ’70s and early ’80s, NL was keeping pace in terms of seismic data acquisition with Norway. In the early ’80s when the oil price collapsed, investment came out of frontier areas, and it took a long time to come back.

There were additional snags along the way. For one thing, the federal govern-ment of Canada was negotiating with the province over offshore rights. This was finally settled in 1985. Additionally, other legislation in Canada made it difficult to get seismic vessels into the area, and that wasn’t settled until 2013. Once those hurdles were overcome, seismic vessels returned to the area within a couple of weeks, Keating said.

The region is ideally located between major energy markets, being roughly equidistant from the North Sea, the Gulf of Mexico and West Africa. It has access to Brent pricing rather than West Texas Intermediate and enjoys broad mar-ket access. It also has a long seafaring history and is a “gateway to the Arctic,” he said.

Yet there are fewer than 200 explo-ration wells in the entire area, which is about one well for every 5,600 sq km (2,160 sq miles). Much of the activity over the past 20 years has focused on development and production rather than exploration due to major discoveries in other provinces. Nalcor was formed to reverse this trend.

“We needed a data solution,” Keating said The company joined forces with PGS

and TGS to acquire a vast contiguous swath of 2-D data using 8-km to 10-km (5-mile to 6.2-mile) offsets. The survey cost $50 million, and Keating said it’s likely the largest contiguous data program in the world. Parts of the survey used very loose grids because the search was not for structures but for entire basins.

“We found two new basins and a recon-figuration of a third,” he said. “This added 200,000 sq km [77,200 sq miles] of sedi-mentary basin.”

The results of the resource assessment that followed have caused a significant uptick in recent licensing rounds, and Keating expects NL to be back on trend with Norway in the next few years.

“It was a methodical approach to basin hunting,” he said. “Now we’re into lead identification.”

A satellite seep survey also was undertaken, which found several seeps in deepwater areas. And cor-ing data have been collected that have been integrated with satellite, seismic, physical and electromag-netic studies and are being made

available through Nalcor’s website, nalcorenergy.com.Nalcor was formed partly to create an environment

in which oil companies would feel comfortable invest-ing. Keating said there are four pillars to improving the region’s exploration potential: prospectivity, fiscal cer-tainty, favorable regulations and industry expertise—in

other words, finding companies with the right expertise that are willing to invest.

Some of the data examples are compelling. Keating showed one example of a structure that was on the same scale as the giant Jubilee Field offshore Ghana. “This is not a play type we’d looked for in the past,” Keating said. Nalcor has so far identified 350 leads and pros-pects—“and counting,” he added.

The ongoing resource assessments are geared to concentrate on each upcoming licensing round, which come in two- and four-year cycles depending how frontier the area is. Keating said the blocks are “big enough to be interesting but small enough to be manageable.”

“Our strategy is to capture a disproportionate share of the exploration market,” he said. n

Tip of the Icebergn NL has a compelling exploration story to tell.

Jim Keating


CONTRIBUTED BY BAKER HUGHES

In complex geological formations optimizing wellbore placement presents a difficult challenge. Failure to

mitigate reservoir uncertainty often results in subop-timal ultimate recovery and increased nonproductive time. The Baker Hughes VisiTrak geospatial navigation and analysis service increases well construction effi-ciency by reducing seismic uncertainty and avoiding costly pilot holes and unplanned geological sidetracks.

The advanced LWD service makes it possible to define reservoir architecture by mapping multiple bed bound-aries in real time without the need for pilot holes that are typically drilled to evaluate the formation before drilling the horizontal portion of a well. The service combines extra-deep azimuthal readings with full interpretation of complex geological scenarios to give operators a better understanding of their reservoirs’ architecture.

The service, which is built on over a decade of reservoir navigation experience using both omnidirectional and azimuthal technologies, consists of four key components:

• A set of sophisticated downhole sensors;• Reservoir navigation services subject matter experts;• Multicomponent real-time inversion modeling soft-

ware; and• Advanced 3-D visualization software.

The VisiTrak bottomhole assembly uses short trans-mitter-receiver spacing to position the modules closer to the bit, which enables earlier detection of remote reservoir boundaries. The modules operate at two fre-quencies, 20 KHz and 50 KHz. For each frequency the VisiTrak service provides long-space measurements of phase difference and attenuation resistivities along with directional signal strength measurements that provide a 360-degree view of the borehole. These measurements provide inputs to the multicomponent inversion mod-eling software, which supports identification of multiple boundaries both above and below the wellbore.

Enhanced azimuthal sensitivity enables operators to detect multiple bed boundaries up to 30 m (100 ft) from the borehole. This depth of detection provides a reservoir-scale view, opening a new frontier in real-time wellbore placement and reservoir mapping by bringing reservoir navigation interpretation from borehole to seismic scale.

The service’s extended-range signal propagation and detection identifies and gathers precise, reliable data that are reviewed and analyzed immediately by experts to enable operators to not only see the target but to drill straight to it and stay within it.

The fully integrated modeling package facilitates fast, interactive updates and full interpretation of complex

geological scenarios as well as real-time collabora-tion on critical geosteering decisions. By identifying approaching beds, boundaries and pay zones far in advance of landing the well, operators can now place wells precisely and efficiently in real time to increase production and improve ultimate recovery. The Visi-Trak service will be featured in the Baker Hughes booth 3731 at OTC. n

BY LEN VERMILLION

When Mexico enacted its historic energy reforms in August 2014, it was with the intention of reversing

the country’s decline in oil production and to make it a world-class producer again. Such reforms won’t hap-pen overnight but have made an impression on some of the top E&P investors worldwide, some of who were on hand Tuesday at the OTC panel discussion, “Mexico’s Sweeping and Historic Energy Reforms: Experiences and Results After First Bidding Rounds.”

“Why Mexico?” asked Christine Healy, vice president of exploration for Statoil Mexico. “We want to be where we are wanted. We have seen in Mexico a clear and pre-dictable policy, and we have been pleased with the dialog with the industry.”

Comparing Mexico’s reforms to past efforts that rejuve-nated other countries, Norway, in particular, Healy labeled Mexico a “new energy frontier.” “Mexico is largely underex-plored,” she told the audience. “While geological prospectiv-ity is very attractive [in Mexico], the sheer scope of Mexico’s energy reform has made it an attractive investment.”

In addition to resource potential, she cited the nation’s commitment to infrastructure growth and an uptick in farm-in opportunities as a key reason for her company’s interest.

The opportunities for international investment in Mexico’s exploration are on the rise since the sweeping overhaul of the nation’s energy sector were signed into law by President Enrique Peña Nieto. It’s opened the door into the country dominated by state-owned petro-leum company PEMEX.

The country’s deputy secretary of energy for hydrocar-bons, Dr. Lourdes Melgar, told the panel audience that the Mexico is in the midst of a “revolutionary transfor-mation” due to the energy reform legislation.

To Healy’s point that farm-in opportunities in Mex-ico are increasing, Melgar said that PEMEX already has requested that 14 of its assigned fields be farmed out. She also said that the country will be holding another round of deepwater bids in December.

“One of the keys to the reforms is to precisely cre-ate competitive markets,” Melgar said. She added that the country needs to establish a stronger institutional

framework, which includes transparency, to have com-petitive markets.

“We must have strong regulators,” she said. In an effort to create further transparency, Melgar

said the company has presented a formal request to join the International Energy Agency and is preparing for candidacy in the Extractive Industries Transpar-ency Initiative.

She also said that the country’s reforms were based on a localized strategy. “The key is to create a base of production inside of the country,” she said.

Melgar said Mexico has instituted a five-year plans to build up both E&P and infrastructure, specifically pipe-lines, in the country. Those plans also include a buildup of potential workforce.

It is the commitment to a long-term strategy that has the attention of potential E&P investors such as Statoil.

“We see that, fundamentally, the energy reform has the potential to result in exploration and resource devel-opment, not only for investors and not only for Mexico, but also for Mexicans who are ultimately the owners of the resources,” Healy said. n

Geospatial Navigation, Analysis Service Optimizes Well Placement n Geospatial navigation and analysis service increases well construction efficiency by reducing seismic uncertainty and avoiding costly pilot holes and unplanned geological sidetracks.

Are Mexico’s Energy Reforms Opening a New Energy Frontier? n How the country’s commitment is playing with international E&P investors was discussed at an OTC panel.

The VisiTrak service combines extra-deep azimuthal read-ings with full interpretation of complex geological sce-narios to give operators a better understanding of their reservoirs’ architecture. (Photo courtesy of Baker Hughes)

As OTC draws to an end, many out-of-town visitors will be flocking to the airport. Fortunately, OTC attendees can receive a discounted fare with SuperShuttle. The SuperShuttle ticket counters are located in the baggage claim area of Bush Intercontinental (IAH) and Houston Hobby (HOU) airports. Tickets may also be purchased onsite at the Airport Shut-tle Desk in lobby D of the NRG Center. Attendees can make a roundtrip

reservation online at supershuttle.com. For more information or to pur-chase tickets onsite at OTC, visit the Airport Shuttle Desk in lobby D of the NRG Center.

SuperShuttle Shared-Ride from IAH is $25 one way, and SuperShuttle Shared-Ride from HOU is $21 one way. The shuttle makes trips to the airport every hour and will run from 10 a.m. to 6 p.m. on Thursday. n

Airport Transportation by SuperShuttle


CONTRIBUTED BY GE OIL & GAS

Drilling operations are moving to deeper waters and harsher environments. It is imperative to have

robust equipment that can withstand the challenges of these environments and allow operators to extend their field life. Subsea equipment has to cope with some of the most severe fatigue conditions in offshore drilling and is affected by a myriad of factors, including vessel motion, larger and heavier BOPs, and extended field operations. This is of particular concern in areas core to the advancement of offshore operations such as the Gulf of Mexico, the North Sea, Sub-Saharan Africa and the Caspian region.

Concerns about system fatigue, particularly in the fatigue-critical zone of wellhead and first-joint con-nections, has driven conservatism and rigorous quality requirements, with increasing technical specifications as a way to ensure fatigue resistance in wellhead per-formance. This significantly adds both time and cost to operations and leads to another challenge in the subsea arena: inefficiency.

Currently, the industry relies on bespoke products for individual operations. Historically, industry specifica-tions have been written to address quality and design. However, a lack of guidelines or accepted standards for fatigue or forging qualifications led to the development of bespoke solutions for every project. In the current environment, with most players having to cope with sig-nificant cost pressure, this is not sustainable.

With several projects running late and/or over budget, the industry continues to suffer from scheduling delays. GE Oil & Gas is looking to solve the problem of fatigue as well as other equipment issues with product standard-

ization and process simplification. The company’s SFX Wellhead System is a result of this vision.

SFX is a standardized system that provides up to 16 times fatigue resistance improvement over GE Oil & Gas’ existing systems for ultrareliability in fatigue-crit-ical zones.

The company developed this technology building on its field-proven MS-700 and MS-800 systems. Rather than moving fatigue issues elsewhere in the system, SFX directly addresses them and maintains stiffness in each component.

The two-year development process involved in bring-ing this technology to market included collaboration with global operators to ensure that SFX meets or exceeds real infield fatigue requirements, enabling more drilling time in harsh conditions with less maintenance and downtime.

Nick Dunn, global leader of Subsea Services & Off-shore at GE Oil & Gas, said, “Currently, a key challenge facing operators is the need to improve efficiencies, eliminate nonproductive time and reduce costs. The SFX wellhead system addresses all these areas, starting a new chapter of reliability, affordability and flexibility for sub-sea wellhead systems.

“Subsea wellheads are a core technology supporting drilling activities, but their lifespan can be affected by a multitude of factors such as vortex-induced vibrations. These loads are transferred through the riser to the well-head and casing system, causing fatigue at critical con-nectors and welds.

“Traditional mitigation techniques led to project-spe-cific customization, which translates into high engi-neering costs and long lead times. While no previously configured system delivered extreme fatigue reliability, cost-efficiency or flexibility across many different instal-

lations, the SFX wellhead system takes a fundamental step in this direction.”

Geometries for the SFX are optimized to reduce stress concentrations in all components. Preload between the high- and low-pressure housings is achieved through casing weight instead of additional tooling, creating a rigid connection for effective load transfer.

For fabrication, lengthened forgings improve thermal effects during welding, tighter pipe tolerances reduce stress and the weld profile is fatigue-friendly. Advanced nondestructive examination techniques ensure material soundness and maximize the probability of detection.

The entire manufacturing process for the SFX has been standardized, from raw material specifications, quality control and component design to system fabrication and installation. GE has significantly reduced cycle time and simplified the procedures involved, including indepen-dent third-party inspections. This approach, along with adoption of DNVGL-RP-0034, means GE Oil & Gas can stock materials and manufacture SFX components globally. Additionally, SFX maintains all the interfaces, tools and operating procedures of existing MS-700 and MS-800 products. n

Simplifying Offshore Operations n A standardized wellhead system offers increased fatigue resistance.

The SFX Wellhead System provides up to 16 times fa-tigue resistance improvement over GE Oil & Gas’ existing systems for ultrareliability in fatigue-critical zones. (Photo courtesy of GE Oil & Gas)

BY JENNIFER PRESLEY

Making the possible of the impossible is the beauty of being the first. But why stop at just one when two

are possible? With its successful installation of two sub-sea gas compression systems at the Gullfaks and Åsgard fields, Statoil took two giant steps closer to realizing its vision of a sea-floor-based subsea factory. The trials and tribulations of the projects that started out as a rough sketch on the back of a napkin in 1985 to fully functional operating compres-sion systems in 2015 were the focus of the OTC technical panel “World’s First Subsea Compression” held Tuesday afternoon.

The panel, led by Svein Hellesmark, 7 Seas Oil & Gas Group LLC, and Herbjorn Haslum, Statoil ASA, included seven pre-sentations that covered all aspects of the projects that were given by the companies involved. Torstein Vinterstø, project direc-tor for Statoil, lead the panel with a detailed project overview he and his co-authors outlined in the OTC-27172-MS paper.

According to Vinterstø, the considerable distances in scale and boosting require-ments are what dictated the two very different technical approaches to the chal-lenging fields. For example, the Gullfaks wet gas compression system is projected to increase recovery from the Gullfaks South Brent reservoir by 22 MMboe using two 5-MW WGC4000 wet gas compressors connected to the existing subsea templates and pipelines about 15 km (9 miles) from the Gullfaks C platform.

For the Åsgard subsea compression system, two 11.5-MW centrifugal compressors will help provide the projected 306 MMboe in increased recovery from the Mikkel and Midgard fields, he said. The compressor system is connected to existing subsea

templates and pipelines 40 km (25 miles) from the Åsgard B platform.

More Tools for the Subsea Toolboxn With its successful installation of two subsea gas compression systems, Statoil adds more tools to its subsea toolbox.

See SUBSEA TOOLBOX continued on page 16


BY CATARINA PODEVYN, INFIELD SYSTEMS

Southeast Asia’s oil and gas sector is no different to any other and faces a challenging period after seeing

a number of project deferrals and operator divestments over the past year.

So how is the current low oil price environment affect-ing developments across the top two producing nations in the region: Malaysia and Indonesia?

In the last five years Malaysia has led Southeast Asia’s offshore development activity. The twin drivers for this are the country’s ambition to become a hub for LNG produc-tion and trade and national oil company Petronas’ push to develop stranded and deepwater fields following the intro-duction of the wider Economic Transformation Program.

Between 2010 and 2014 Infield’s research shows Malaysia’s deepwater capex demand (in more than 500 m [1,640 ft] of water) increased by a compound annual growth rate of 16%, driven by projects such as the Shell-led Gumusut-Kakap development and the Petronas FLNG-1 project.

PFLNG-2 delayHowever, with the prevailing commodity environment, deepwater projects—where economic viability often is marginal—are now seeing delays and cost reassessments.

The latest delay is to the Petronas PFLNG-2 facility, which comes as part of the operator’s cost optimization program following a 25% fall in revenue between 2014 and 2015. With the historically low oil price level expected to continue throughout 2016, the operator is now looking to rephase the development, bringing the facility onstream later than the originally planned date of 2018.

With Petronas cutting its capex and opex budget by RM50 billion (US$12.8 billion) over the next four years, there may well be further project deferrals over the remainder of this year.

Despite this, the overall outlook for Malaysia’s offshore sector remains positive. The first of Petronas’ floating LNG (FLNG) facilities, the newly named FLNG SATU, is expected to head to the field in second-quarter 2016, while the Petronas-operated Baronia, Bardegg-2 and Tukau Timur projects also saw key contract awards in 2015.

Shell and Murphy are expected to remain the leading foreign operators. Shell’s key projects over the 2016-20 timeframe will include the continued development of Gumusut-Kakap and Malikai, while Murphy’s expendi-ture will remain focused upon the development of the deepwater Rotan Field in partnership with Petronas.

Indonesian production declineThe rise of Malaysian activity contrasts with the declin-ing production and ongoing lack of investment offshore Indonesia, which faces the prospect of becoming a net gas importer before the end of the decade.

Indonesia had been expected to match Malay-sia in terms of offshore capex by 2020, but the recent announcement that the Inpex-operated Abadi Field is now to be developed via an onshore facility instead of the original offshore FLNG scheme casts doubt on this.

Following the start of the main phase of production from the Banyu Urip (Cepu) Field last year, Indonesia reactivated its membership of OPEC after a seven-year hiatus. However, the country remains a net importer of oil, and this is largely seen as a strategic move with Indo-nesia offering a guaranteed market for exports and also acting as a gateway to Southeast Asian markets.

All this compounds the significant uncertainty that surrounds the future of Indonesia’s offshore sector. Chevron’s IDD project is expected to be delayed once again, while a number of international operators have divested assets in the country over the past year. The preference for an onshore facility over a more cost-ef-fective FLNG concept for the Abadi development also highlights another of the challenges within the Indo-nesian upstream sector; the state is looking to realign production to focus on domestic consumption and also increase local content.

UncertaintyEven when oil prices were stable, the Indonesian oil and gas sector had been facing an uncertain period following the disbandment of independent oil and gas regulatory authority BPMIGAS in 2012 and the establishment of temporary body SKKMIGAS.

A revision of oil and gas law is scheduled for this year, which could result in further upstream reforms. However, this could work against foreign operators, with greater state involvement a likely outcome. The Indonesian upstream sector already suffers from excessive red tape, and with the prevailing market conditions it could be that more independent oil companies (IOCs) exit the country.

While a number of North American IOCs already have withdrawn to focus investment on unconven-tional projects closer to home, regional markets such as Myanmar and Philippines might benefit from operators realigning interests within Southeast Asia.

With commodity market conditions unlikely to improve significantly before year-end 2016, operators active within Southeast Asia are expected to focus on consolidating their market positions and finding opera-tional efficiencies during the remainder of 2016.

Over the longer term both Malaysia and Indonesia are expected to see increases in offshore capex demand, which will be driven by those projects that have been deferred over the last year, in particular the Rotan PFLNG-2 development and Chevron’s IDD project. n

Malaysian Sector Staying Strongest in Southeast Asia n A five-year offshore forecast for Malaysia and Indonesia shows the former stretching away from the latter in the short term.

0%

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2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Malaysia Indonesia Thailand Vietnam Myanmar Brunei Philippines Cambodia Singapore

Malaysia remains the No. 1 country for offshore capex demand over the 2011-20 period in Southeast Asia. (Data courtesy of Infield Systems)

Service Model Designed to Make Operations More EfficientTenaris’ Rig Direct is a service model that is designed to make operations more efficient. As an integral part of this strategy, Tenaris is investing in a $1.8 billion seamless mill in Bay City, Texas, nearby the Permian Basin and Eagle Ford shale plays. The new facility is expected to be fully opera-tional in 2017. Also, new service centers in Freeport and Midland, Texas, grant Tenaris flexibility in delivery times and add convenience to customer operations. The pillars of the Rig Direct service are being shown at OTC booth 4741 using a new virtual reality application. Attendees also can view the benefits of the company’s new PipeTracer service.

Halliburton’s Landmark Introduces Latest Well Construction SoftwareLandmark, a Halliburton business line and provider of E&P software, has released EDT 5000.14 (Engineer’s Desk-

top). This is a major upgrade of the industry’s only com-plete and integrated suite of well construction applications.

“With the industry facing severe pressure to lower costs per well and manage risk, EDT responds with added func-tionality and improved usability to allow engineers to better design, execute and optimize well construction operations,” said Nagaraj Srinivasan, Landmark vice president.

The new EDT delivers added functionality by introducing the CasingWear application. CasingWear facilitates more accu-rate modeling of casing integrity and has been vetted by a major operating company. This company has already used the appli-cation to achieve significant cost savings and to increase safety.

The EDT suite is powered by Landmark’s DecisionSpace Platform, the first enterprise-scale, standards-based open plat-form for E&P companies.

Enhancing Critical Machinery MonitoringSKF’s IMx-M is a protection system that incorporates condition monitoring. The system protects and monitors

critical and high-speed rotating machinery: power gener-ation, pumps, aero engines, steam or gas turbines, motor-run systems—any machine that has high potential energy that could cause severe damage. It’s a sophisticated way of monitoring the condition of critical offshore machinery. Together with SKF @ptitude Monitoring Suite software, it enables end users to protect and enhance the reliability of assets and reduce machine downtime. n

Industry News

The IMx-M protection system incorporates condition monitoring. (Image courtesy of SKF)


BY ERIN PEDIGO

In February, the Republic of Ireland’s government launched the 2015 Atlantic

Margin Licensing Round, which was the most successful licensing round in Ire-land’s history.

With attention on its Atlantic Margin emerging frontier area, offshore Ireland is now being viewed as possibly analogous to the western Atlantic Ocean, which holds some of Canada’s offshore basins that are currently being explored by supermajors in an area known as the North Atlantic Jurassic Oil Superhighway. During the late 1970s, Ireland’s hydrocarbon potential was made analogous to the North Sea region.

“Ireland’s offshore area is vast but under-explored,” despite more than 50 years of E&P work, according to Brian Carroll, the assis-tant secretary general for natural resources at the Department of Communications, Energy and Natural Resources—Ireland. He and Tony Reilly, CEO of Providence Resources Plc, discussed commercial oppor-tunities in Ireland’s oil and gas sector at an industry breakfast on Wednesday at OTC.

Ireland’s overall economy has changed over the decades, and its energy sector currently embraces the latest industry technology in the hopes of exploring and developing all areas, including those underserved. At 700,00 sq km (270,271 sq miles), Ireland’s entire designated offshore area is 10 times its land area, Carroll said.

Both 2-D and 3-D seismic are valuable technologies. Reilly said there is a hard chalk bottom in the Celtic Sea. The most sophisticated seismic technology would be needed to properly observe it. “Three-di-mensional seismic is breaking through,” he said. The Celtic Sea area is separate from the Atlantic region and is open in terms of licensing, Carroll noted.

The Donegal, Erris, Slyne and Rockall basins; the Porcupine area; the Gobar Spur were the three main areas auctioned in the 2015 Atlan-tic Margin round, which provided licenses for up to two years. Carroll said standard licenses applied toward shallow-water areas, which are off the south and east coasts. Deepwater areas are off the west coast, he added.

Ireland’s Atlantic Margin Licensing Round Provides Great Expectations n The import-dependent nation is in the aftermath of its most successful licensing round, with attention on its Atlantic Margin emerging frontier area.

“Ireland's offshore area is vast but underexplored.”

—Brian Carroll, Department of Communications, Energy and Natural

Resources, Ireland

See IRELAND continued on page 20


BY DOUG MARTI, TRELLEBORG OFFSHORE AND CONSTRUCTION

Fire protection is a critical part of onboard safety, and reducing the risk of fire hazards is a vital and challeng-

ing part of designing and engineering offshore oil and gas installations. Trelleborg looks at why innovative corro-sion-free, rubber-based solutions can be the key to ensur-ing that people, structures and equipment are protected.

For optimum fire safety, choosing the most suitable material is imperative and as technologies advance, rub-ber-based materials are becoming a more popular choice within the offshore industry due to their flexibility and durability. Compared to alternative materials, such as steel, ceramic wool or fiberglass, rubber can withstand more extreme temperatures, weather conditions, vessel movements and offers an exceptionally high durability. It is a diverse material that can damp, seal and protect, and importantly, it has an extremely long lifetime.

Safety firstCritical to delivering onboard safety are advanced fire protection systems. Their performance is essential for the safety of personnel, asset protection and preventing event escalation. Examples of these systems include plat-form surface protection, onboard deluge systems and coating for pipes and flanges.

The harsh offshore weather environment causes metal products and components to be susceptible to rust and corrosion, which is detrimental to the performance and function of the platform. Additionally, ceramic wool and similar materials used for fire protection will become less effective when wet. This simply isn’t an option as demands offshore become greater.

Passive fire protectionFirestop solutions are available in a series of mate-rials and products to protect personnel, equipment,

critical components and structures, and to assist emergency response activity by buying time to gain control of a fire and evacuate an area. Rub-ber has the capability of withstanding weather conditions, vessel movements, providing ease of inspection and fire protection over the life of a project.

Some projects require a protected surface area temperature that does not exceed a certain level throughout the fire exposure period. For these types of requirements, insulation materials are used in conjunction with firestop fire protection. The critical temperature on the surface of a component is project specific information, with typical values to a maximum of +200 C to +400 C (392 F to 752 F) while the generation of smoke and nontoxic fumes must remain low.

Firestop applicationsBy avoiding hot work onboard, fire hazards and shutdown requirements can be reduced. Surface protection designs that can be installed using other techniques should be prioritized. Surface tiling should feature insulation to isolate fire temperatures from areas below and should also ensure a nonslip surface for worker safety. Sophisticated coating designs can with-stand blasts of up to 2.1 bars and jet/hydrocarbon fires for more than 2 hours.

Other areas of the topside considered for fire resis-tance are nuts and bolts used in flanges—one of the weakest areas of any platform. Typical fire protection, which covers the complete flange, will not allow easy inspection of the units. By protecting only the nuts, reg-ular inspection can be performed, reducing installation time and overall weight. By using molded rubber-based material on just the flange nuts, this protects the stud bolts from elongating and the flange from breaking the seal during a fire.

ConclusionBy installing effective and reliable firestop systems onboard, the safety of offshore oil and gas instal-lations will be increased. In the harsh offshore and onshore oil and gas industry, operators need the assurance of a material that delivers proven perfor-mance, without fail.

It is the responsibility of the manufacturer to ensure that they can provide high-performance and reliable solutions. Now more than ever operators should look to work with manufacturers who can provide the most advanced solutions guaranteeing performance and safety. Operators should have access to the latest and most inno-vative solutions that will significantly improve onboard safety and provide peace of mind to all those on board. n

Flexible Fire Protection for Offshore Applicationsn By installing effective and reliable firestop systems onboard, the safety of offshore oil and gas installations will be increased.

This illustration shows the FireNut component, which is a jet fire protection for bolted connections in an offshore platform and de-signed to extend service life in the event of a fire. (Image cour-tesy of Trelleborg)

BY RHONDA DUEY

Concurrent with the rise of the shale plays in North America was the discovery of the presalt province

offshore Brazil. The province, composed of carbonate reservoirs and microbial and coquina rocks, covers parts of the Santos and Campos basins at a depth of more than 5,000 m (16,404 ft). Since the discovery well at Lula, sev-eral other fields have been discovered that produce more than 1 MMboe/d.

According to a presentation by Paulo Roberto Schro-eder from Petrobras, the decade since the presalt dis-covery has led to major progress in the application of geophysical technologies to aid in reservoir character-ization and monitoring. This has in part been necessi-tated by the challenges inherent in presalt exploration and development:

• Complex 3-D velocity fields;• Interbedded multiples;• Variation in facies and diagenesis in carbonates

more so than clastics;• Low seismic resolution;• Acoustic impedance ambiguity;• Unstable elastic impedance results; and• Uncertain 4-D results.The team starts with special acquisition and process-

ing techniques to optimize the geophysical information. It uses illumination studies to delineate the acquisition

design and inter-bed multiple attenuation to model and attenuate the multiple reflections. Broadband processing techniques are also useful.

Petrophysical modeling helps identify the param-eters of the rock-fluid system that influences the seis-mic response. The resulting petrogeopysical model is calibrated using plugs, side samples and well logs. The parameters are cross-plotted against the acoustic or elas-tic response, and acoustic or elastic stress attributes show the variation in saturation effects. Commonly used attri-butes include impedance of compressional and shear waves, velocities of compressional and shear waves, Poisson’s ratio and various combinations of these. This analysis helps determine the likelihood of obtaining a 4-D signal in subsequent surveys.

The complexity of these reservoirs and the overburden leads to complex seismic velocity fields, causing wave front distortion. Thick layers of salt distort the image unless velocity variations for seismic migration are taken into account. To overcome this, Petrobras develops a high-resolution, highly accurate velocity model from prior velocity field analysis, well logs, a time-depth table obtained from the synthetic trace at the position of the wells and the geological model. This aids with accurate prestack depth migration, which generates an imped-ance volume and velocity for the reservoir characteriza-tion or rock properties prediction. More recently it has also been used for geomechanical studies.

The next step in the process is transforming the seismic data into a quantitative description of reservoir properties on a seismic scale. Seismic inversion provides the attri-butes that represent lithology and fluid content. A method to predict seismic facies completes the interpretation.

The final interpretation includes information from amplitude, impedance volumes, seismic attributes and facies, well logs, cores, interpreted geological marks and geological correlations. Special techniques to extract and interpret the attributes are used to for the structural char-acterization. Geophysical techniques can also be used for geomechanical studies. Petrobras models the salt layer using derived velocity models and elastic seismic inversion.

The company also conducts studies for 4-D feasibility. It has developed a workflow based on case histories in the Campos Basin. It uses rock and fluid properties to run fluid substitu-tion equations. From dry compressibility and Poisson’s ratio, estimated from elastic inversion, rock and fluid properties can be substituted to derive multiple petroelastic model scenarios.

Then a 4-D synthetic volume is created that models multiple years of production. This model is calibrated for the next potential survey.

Most recently Petrobras has been using nodal tech-nology to quantify the 4-D signal of the presalt micro-bial carbonates, to better image the layers under the salt, image a 30-sq-km (11.6-sq-mile) reservoir under pro-duction in the Santos Basin and monitor injectors and producers in the water-alternating-gas project. n

Workflow Aids in Reservoir Characterization n Combining and advancing geophysical and petrophysical measurements helps with presalt understanding.


CONTRIBUTED BY LLOYD’S REGISTER ENERGY

Given the increasingly central role of data and con-nectivity, cybersecurity is widely accepted as a major

risk to the sector and society as a whole. Furthermore, as technology becomes more accessible, the skill pool of associated “dark arts” expands, and the risks increase.

View from the boardroomAt a recent executive briefing event hosted by Lloyd’s Reg-ister Energy, it was recognized that those responsible for cyberattacks are highly skilled, not constrained by the law and driven by a range of motivating factors. While there is significant activity across the sector to mitigate the potential impacts, many of those present felt that the level of response might be insufficient and/or misdirected.

Some executives felt that adequate measures were in place to protect against data theft and hacking but that operations remain vulnerable, making interruptions a likely outcome in the event of a cyber-security breach. It also was suggested that most oil and gas sector companies do not yet have in place the systems and resources required to precisely determine the source of cyberattacks or with what frequency they occur to implement preventative measures.

During the discussion, executives largely agreed that a standardized approach to cybercrime is vital. As cybersecurity threats have gained currency relatively recently, the International Association of Drilling Contractors (IADC) is in the process of developing recommended practices (based on ISA/IEC 62334). Once published, this will give drilling contractors and operators some guidance on the measures they should be taking. However, the area remains largely unregulated, and much depends on the atti-tude of individual companies.

What can the industry do?Dr. Richard Parliman, lead technical spe-cialist on cybersecurity, is driving efforts to equip the energy industry to defend itself. He said, “The industry falls into two camps. There are those who want to imple-ment strong protective measures, and then there are those who think there’s no real risk and don’t take it seriously.”

Alongside the increased threat and heightened profile, anti-virus software products struggle to keep up. Most virus checkers only search for and detect the most common viruses and malware.

Parliman supports the view that cyber-security is at an early stage of development throughout the industry, and not enough is known about the sources and frequency of attacks. Of course, responses and capability varies, with some companies committing resources and focus to advance in this area. Other, usually smaller, companies lack the scale required to develop solutions, so they will look to external sources. Parliman is hopeful that the recommendations being developed by the IADC will help.

Connectivity equals vulnerabilityThe increasing digitization of the sector has elevated the risk associated with cyberattacks because hackers can now access data and systems from the outside. With

the utilization of marketed rigs going down and the stacking and decommissioning of some of the older rigs, this is going to become more of an issue. In the process, they’re naturally getting rid of the older rigs because required maintenance costs are high, and modern tech-nology increases overall safety and whole profile perfor-mance. In addition, newer rigs can be more connected, allowing better onshore and offshore monitoring.

Knowledge sharing Cybersecurity skills are vital for today’s sector. This means training or investing in specialists as well as

operational teams so that actions and processes are thoroughly considered in the context of cybersecu-rity. Lloyd’s Register Energy has developed a set of procedures to help energy companies tackle cyber-security issues. Parliman describes these as a high-level view of the systems, equipment and personnel on a rig or a facility; it is a means of evaluating which elements are most vulnerable to attacks and then comparing their condition to international and regional standards.

Visit Lloyd’s Register in hall A, booth 5171 at OTC or go online at lr.org/energy for more information. n

Cybersecurity: A Top Priority for the Energy Industryn Cybersecurity is at an early stage of development throughout the industry, and not enough is known about the sources and frequency of attacks.


BY VELDA ADDISON

The U.S. Department of Interior has unveiled a hefty package of well control regulations that require real-

time monitoring for deepwater and HP/HT drilling, more controls on maintenance and repair of BOPs and third-party reviews, among other rules.

The 531-page final well control rule, which takes effect 90 days after its publication in the Federal Register, were delivered about a year after the administration’s proposal on well control regulations was first released and less than a week away from the April 20, 2010, the deadly Macondo well blowout and Deepwater Horizon rig fire in the U.S. Gulf of Mexico.

Regulators have taken strides since the tragedy to strengthen, update and modernize energy regulations to ensure that oil and gas development offshore is carried out safely, Secretary Sally Jewell said during an April 14 conference call.

“We’ve made sweeping safety reforms, overhauling federal oversight by establishing independent regulatory agencies that have clear missions and are better resources to carry out their work while keeping pace with the rapidly evolving industry,” Jewell said. “We’ve strengthened drill-ing and emergency response standards for oil and gas com-panies, and we’re raising the bar through new standards for well design, production systems, blowout prevention and well control equipment. Industry, too, has stepped up to strengthen the culture of safety and cooperation.”

Some of the rules already have been adopted by the industry, which created its own standards, improved oper-ating procedures and devised better technology following the tragedy. The use of double shear rams in the BOP stack is one of the rules that is now a baseline industry standard.

The final rule, as stated by the Bureau of Safety and Environmental Enforcement (BSEE), includes:

• Minimum baseline requirements for the design, manufacture, repair and maintenance of BOPs;

• Additional controls over BOP maintenance and repair, including an annual mechanical integrity assessment report on certain BOPs by a BSEE-ap-proved verification organization;

• A requirement that BOP systems have technology that allows drillpipe to be centered during shearing operations;

• More rigorous third-party certification of the shearing capability of BOPs;

• Real-time monitoring capability requirement for deepwater and HP/HT drilling activities, a practice that already is carried out by most deepwater opera-tors. The rule helps ensure BSEE has access to the data;

• Criteria for testing and inspecting subsea well con-tainment equipment; and

• Additional requirements for using ROVs to func-tion certain components on the BOP stack.

The regulations, which build on findings and recom-mendations from several reports and investigations with industry input following Deepwater Horizon, also require adequate centralization of casing during cementing and mandate use of accepted engineering principles for drill-ing and completion equipment among other requirements.

“We listened extensively to the industry and other stakeholders and heard their concerns loud and clear—about drilling margins, blowout preventer inspections, accumulator capacity and real-time monitoring,” Assis-tant Secretary for Land and Minerals Management Jan-ice Schneider said in a statement. “This rule includes both prescriptive and performance-based standards that are based on this extensive engagement and analysis.”

BSEE Director Brian Salerno said the Interior Depart-ment heard from more than 170 commenters, including from industry representatives technical issues. “We rec-ognize that it was important to collect the best ideas on the prevention on well control incidents and blowouts to assist of the development of the proposed rule,” he said. “This includes the incorporation of knowledge and skillsets the industry has.”

But industry concerns remain.A day before the final rules were unveiled, the Ameri-

can Petroleum Institute (API) reiterated its concerns and did so again following the release of the final rule. The API, which has devised 275 E&P standards that cover offshore operations including well design and BOPs, said the rule might have unintended negative consequences.

Among industry concerns were requirements for more accumulators to satisfy larger volumetric requirements, which would lead to larger and heavier BOP stacks than used today, and an “infeasible implementation timeline” considering sev-eral of the provisions require a BSEE-approved verification organizations to perform verification or certification service.

Randall Luthi, president of the National Ocean Indus-tries Association, pointed out that some of their con-cerns were addressed.

“When regulations require retrofitting existing equip-ment or the use of new technology, it is best to have a reasonable implementation time. This was important to the industry, and on that aspect BSEE agreed and extended many of the proposed timelines,” Luthi said. “However, the final language on the prescriptive drill-ing margin may not completely address valid concerns expressed by some of our members.

“Therefore the implementation scheme of that section will be key as regulators move forward under the rule,” Luthi added. “There may very well be more earwigs tucked away in the corn, but we are just now beginning to peel back the layers of this massive rule.”

Additional concerns also were raised in the 216-page July 2015 comment sent to the Interior Department from NOIA, API and five other industry groups.

“Offshore oil and natural gas development in the U.S. is safer than ever before thanks to diligent, continuous indus-try leadership and efforts of industry and regulators,” said Erik Milito, API’s upstream group director. “It is imperative that BSEE ensure any new regulatory requirement does not unnecessarily erode the strong safety and national security gains that have been achieved in the last half decade.

“Energy development in the Gulf of Mexico has helped make the U.S. the No. 1 producer of oil and natural gas in the world and has made us energy secure. This rule will affect every offshore energy project for years to come. It is essential to get it right.” n

US Issues New Offshore Well Control, Safety Regulationsn The use of double shear rams in the BOP stack is a baseline industry standard that is now one of the rules.

“Offshore oil and natural gas devel-opment in the U.S. is safer than ever before thanks to diligent, continuous industry leadership and efforts of industry and regulators.”

—Erik Milito, API

In his presentation, Vinterstø noted that while each field was a separate project with its own business case, management of the project was con-ducted by a central team to ensure transfer of lessons learned and best practices between the fields. Statoil worked with OneSubsea and other key suppliers to qualify the helico-ax-ial multiphase technology used in the wet gas compression system. The operator worked with Aker Solutions and key suppliers to qualify the tech-nology utilized within the Åsgard centrifugal compression system.

Startup of the Åsgard systems occurred in September 2015, with the Gullfaks compressors going online in October 2015. Both systems have experienced little to no downtime since startup.

For a complete list of session papers and authors for the “World’s First Subsea Compression” technical panel, please see the daily technical lineup at 2016.otcnet.org. n

SUBSEA TOOLBOX (continued from page 11)


BY MARK THOMAS

A nine-well plug and abandonment (P&A) campaign in the deepwater Gulf of Mexico

(GoM) by Wild Well Control Inc. already has seen work on five subsea wells suc-cessfully performed using the company’s DeepRange cementing tool.

Used in connection with its 7Series ris-erless intervention system, the company is employing the rigless technology in water depths of up to 2,134 m (7,000 ft). In a presentation at a press conference at OTC, Wild Well Control said its tool is certified to depths of up to 3,048 m (10,000 ft) and a maximum working pressure of 10,000 psi.

According to Martial Buguieres, Wild Well’s vice president of marine well ser-vices, “The new tools and techniques used on this project already have exceeded expectations. Our methods offer reduced costs while maintaining full BSEE [Bureau of Safety and Environmental Enforce-ment] compliance.”

Each of the wells used the new Deep-Range tool to isolate an outer annulus by perforating and then circulating a mini-mum of 61 m (200 ft) of cement in place and pressure testing the binary plug as per BSEE regulations. “This is not a ‘perf and squeeze’ tool,” the company stated in the presentation.

The technology and methodology will help operators reduce their subsea P&A liabilities, it added, as riserless opera-tions represent dramatic cost reductions when compared to traditional subsea P&A operations.

Wild Well, a Superior Energy Services company, outlined in its presentation that the GoM campaign presented “significant technical issues,” including extreme water depths, gas wells prone to hydrate for-mation and tree communication/control issues. New tools and techniques developed to overcome these challenges included a concentric circulating system, a well inter-vention controls system and extensive hydrates prevention/mitigation procedures.

The company added that so far the tool—deployed using a multiservice vessel—is outper-forming the timeline set by its client as well as its

own internal goals, and that all plugs set with the DeepRange tool have tested successfully first time each time. n

Expectations Exceeded on Riserless P&A Campaign in GoM n Cementing tool is certified to depths of up to 3,048 m and a maximum working pressure of 10,000 psi.

Plan now to attend OTC Brasil from Oct. 24 to 26, 2017, in Rio de Janeiro. OTC Brasil is one of the world’s foremost events for the development of offshore re-sources in the fields of drilling, E&P and environmental protec-tion. It is organized by OTC and Instituto Brasileiro de Petróleo, Gás e Biocombustíveis. Visit otcbrasil.org/Content/OTC-Bra-sil-2017 for more information.

OTC Brasil 2017


BY AARON SINNOTT, WEATHERFORD

Each tubular string that goes into a well affects over-all integrity. Even one improper connection can lead

to a functional failure and detrimental consequences. Whether operating in challenging deepwater or con-ventional land, the optimal technologies and a capable service provider can help to create a well with long-term value, dependable isolation and a lifetime of integrity.

As a global leader in tubular running services, Weath-erford assists operators with making the right connec-tions to enhance safety, manage risks and achieve cost efficiency. The services establish virtual connections that enable real-time monitoring, physical connections that integrate mechanized equipment into existing rig pack-ages and tubular connections that meet manufacturer makeup specifications. The service teams can adapt to any operational scenario for safer, faster outcomes.

Building better wells Weatherford has the infrastructure to connect with a world of operators. Services and solutions launch from strategic points where and when clients need them. Widespread regional and office locations, manufacturing bases and engineering facilities—in Houston and Lan-genhagen, Germany—provide support. Together, these global facilities employ more than 3,000 specialists in tubular-running products.

Weatherford offers tubular running that goes beyond the scope of conventional services with no compromise on personnel safety or well integrity. These services have been

applied in every geographic region and virtually every drilling environment. A worldwide training program graduates tubular-running personnel who meet perfor-mance-based competency standards with 100% mastery.

Enhancing safety, reducing risksRemote connections can minimize risks to personnel and at the same time promote well integrity. The JAM-Pro Net system and TorkPro 3 software creates a virtual connection from which anyone can monitor premium pipe makeup operations. Remote viewing capability reduces the number of persons on the rig floor, which

enhances safety, and real-time access to connection data enables assessing tubular integrity during running.

By providing rig-ready pipe, tubular management facilities enhance the integrity of tubular connections while reducing running times and costs. These facilities monitor the connections of double, triple or quad stands onshore and off the critical path—before delivering them to the offshore wellsite. The result is properly torqued pipe that minimizes the risk of connection failures. For more efficient online work, modular tubular-running equipment connects to operators’ existing rig systems in a way that provides the least disruption to the current package and preserves valuable rig floor space.

Differentiated technologyA tubular-running portfolio including a variety of tech-nologies contributes to well integrity. The LinkMaster tong adaptor—a component of the modular equipment solutions already mentioned—establishes compatibil-ity between a drilling-package positioning device and a Weatherford tong for pipe running. The preassembled adaptor and tong can be installed in one lift, and the adaptor can be vertically adjusted to the height of the tong to run pipe of varying heights and gripping areas more efficiently.

Installed as part of a tong, the hydraulic free-float-ing backup (FFBU) system not only secures a proper connection but also minimizes the potential for dam-age during makeup and breakout. The FFBU virtually eliminates shearing and bending forces that can deform casing and affect long-term integrity. n

CONTRIBUTED BY FRANK’S INTERNATIONAL

New technologies that help unlock oil and gas in chal-lenging locations are essential, especially in today’s

tight cost environment. What drillers demand today are solutions that minimize upfront costs and maximize wellbore success, because total cost of ownership is the bottom-line number that counts most.

Frank’s International offers E&P companies products and services designed to conquer complex reservoirs. Frank’s knowledge encompasses onshore, mid-water shelf and deepwater environments. Most familiar for its tubular running services, Frank’s International also offers well completion, intervention and recovery equip-ment and services.

At this year’s OTC, attendees can explore technology advances that include Frank’s new Xtreme3 Premium Connectors, which are designed to handle extreme requirements. The deepwater, premium threaded con-nector features a metal seal, deep-stab and negative load flank to ensure increased performance and reliability. This connector was developed for the three provinces governing its name: Extreme Tension, Extreme Com-pression and Extreme Bending.

Attendees also can learn about Frank’s Remote Tong Systems that range in different styles developed to support multiple applications. This wide range of specialized sys-tems with various configurations of hands-free operations optimize production and assure long-term success. These remote tong systems can provide electronically preset torque and speed and eliminate need for a hydraulic power unit.

Frank’s International also is showcasing new casing running tools, innovative deepwater completion run-

ning solutions and other drilling technology offerings. Frank’s casing running tool technology achieves desired results even in troublesome horizontal sec-tions while maintaining makeup integrity that provides a safer and more efficient operation. Frank’s casing running tools are multi-functional in that they can fill, rotate, circulate and reciprocate the casing string to the desired total depth. Patented thread compensator technology assists with thread makeup integrity and reduces potential for thread damage during makeup. The cas-ing running tool works in tan-dem with the praying mantis and horseshoe single-joint elevator to reduce the presence of rig per-sonnel in red zone areas, thereby improving safety and efficiency.

Frank’s is an expert in not only properly installing cas-ing but also protecting its integrity throughout the entire life cycle. Frank’s new 6⅝-in. drillstring torque reduction subs were recently introduced to the Gulf of Mexico with great results. By preventing hazardous casing wear, the tools saved an operator from compromising the structural integ-rity of the well and avoided millions of dollars in lost time. The drillstring torque reduction tools also have been used in highly deviated complex wells to significantly reduce torque where the drillstring was previously at max torque capacity.

Frank’s International’s deepwater completion run-ning services apply the firm’s engineering expertise and customized solutions to bring the most complex wells into production more efficiently. Frank’s specializes in corrosion-resistant alloy running operations and has developed a patented product line designed to handle these critical materials, offering the industry’s only true nonmarking tubular running solution.

Booth visitors are invited to bring their biggest drilling conundrums to challenge Frank’s experienced engineers. For more information, visit Frank’s International at OTC booths 160 and 1605. n

Making All the Right Connections for Well Integrity n Running tubulars without services that support connection integrity can compromise the well.

Minimizing Upfront Costs, Maximizing Wellbore Success n Total cost of ownership is the number that matters most.

A Weatherford 21-300 riser tong can make up thermal sprayed aluminum–coated riser connections with no pene-tration of the riser joint while providing up to 100,000 ft-lb of torque. (Photo courtesy of Weatherford)

Running casing is made safer with technology advances. (Photo courtesy of Frank’s International)


CONTRIBUTED BY SIEMENS

In 2008, Det norske discovered hydrocarbons in the Ivar Aasen Field some 180 km (112 miles) off the

Norwegian coast. When the plan for development and operation was approved by the Norwegian parliament in May 2013, the company immediately started prepar-ing to build an offshore platform to exploit the field—an important milestone in the company’s history.

Named after the famous Norwegian poet Ivar Aasen, the field is Det norske’s first major development project as an operator. The field’s lifetime is expected to be 20 years and, at present, reserves are estimated to be 200 Bboe. With Statoil, Bayerngas, Winter-shall, VNG, Lundin and OMV as partners, Det norske will invest 27 billion Norwe-gian kroner (US$3.3 billion) to ensure a good and safe development of the field. “Ivar Aasen makes us a significant player in the oil and gas industry on the Norwegian shelf,” said Geir Westre Hjelmeland, vice president of the Ivar Aasen asset for Det norske. “That is why we carefully selected partners for this project, as close cooper-ation and alignment are critical to secure a project that delivers on HSE standards, quality, schedule and cost.”

Integrated solution for integrated operationOne major package comes from Oslo and Trondheim in Norway, where a team of oil and gas specialists from Siemens worked over the past two years to create the foundation for integrated operation at the Ivar Aasen project. Specifically, the team presented a solution for networking the onshore control room at Det norske’s headquarters in Trondheim with the off-shore control system, plus supplying a data acquisition and visualization system for operations management based on XHQ.

For Det norske, integrated operation is key to meeting production goals and facilitating an efficient work process, both offshore and onshore. For this purpose, the company has two mirroring control rooms, one located offshore on the Ivar Aasen platform and the other onshore in Trondheim. The question, Hjelmeland said, is how to best utilize avail-able resources to ensure safe and efficient off-shore operations. That includes support for maintenance scheduling and planning; the ability to effectively hand over tasks between the onshore and offshore teams; and support for daily offshore operations through analy-sis, studies and good planning. With Simatic PCS 7 and XHQ, Siemens was able to pro-vide the right solution for this integration of teams, data and expertise.

Siemens also offered the best overall package for the entire electrical, instru-mentation, control and telecommu-nications package. All the systems for electrification, process automation and operations management had to be deliv-ered as one project. But technology alone

was not everything, as Hjelmeland explained, “We saw that in addition to offering proven and reliable tech-nology, Siemens also had the right spirit to bring to the project. We wanted a team that would support the hands-on approach that we had chosen for the project, that would be proactive and work as a joint team with all the other partners to find the best solution. And Sie-mens was able to live up to this expectation.”

On track for first oilIn mid-2015, the jacket for the new platform was shipped from the yard in Sardinia and installed on the seafloor above the Ivar Aasen Field. At the same time, Siemens delivered the systems for the EICT package to the yard in Singapore, where they were installed on the platform modules. The onshore control room at the

Det norske headquarters was set up. The next big mile-stone is scheduled this year, when the platform topside will travel by sea from Singapore to the North Sea for installation and commissioning. In late 2016, Det norske will be ready for “first oil”—as the next big step toward becoming a leader in oil and gas production on the Nor-wegian shelf. Hjelmeland is pleased with the progress so far. “When you work with so many teams and partners, trust is very important. You have to understand each other’s motivation to create the best possible solution, and you have to work together as an integrated team. And I have to say that with Siemens, we have a partner that is very like-minded in that respect; they take a very proactive approach to the project and have proven to be a reliable partner, which is just what we are looking for,” Hjelmeland said. n

Integrated Operations Key to Ivar Aasen Field n More than $3 billion will be invested to ensure the safe development of the field.

“Ivar Aasen makes us a significant player in the oil and gas industry on the Norwegian shelf."

—Geir Westre Hjelmeland, Det norske


The new Glen Lyon FPSO vessel will be able to process and export up to 130 Mbbl/d of oil and store up to 800 Mbbl of oil.

The vessel was scheduled to head to Norway in March or April for commissioning prior to startup toward year-end 2016.

Shell, meanwhile, has a swathe of projects on the horizon including Brent decommissioning, redevelop-ment of the Penguins Field and Brent Charlie and a subsea tieback project on Fram.

EnQuest has multiple projectsEnQuest has revealed plans to build a new pipeline from its northern North Sea Thistle Field to Cormorant

Alpha because of the decommissioning of the Dunlin Field infrastructure.

The current 16-in. Thistle oil export pipeline route runs 30 km (18.64 miles) to Dunlin before heading on to Cormorant Alpha and the Sullom Voe terminal, but Fairfield Energy’s decision to shut down Dunlin has left EnQuest in the lurch.

The planned pipeline highlights EnQuest’s desire to continue to invest in its North Sea assets.

The company, which is the largest independent oil producer in the North Sea, last year started up pro-duction on the Alma/Galia Field.

Plans are now being finalized for the next step in the Kittiwake project, with tiebacks planned from the nearby Scolty and Crathes fields. The company’s Quad 9 Kraken FPSO project also is on track, on budget and on schedule for first oil in 2017.

John Cowie, in charge of the northern North Sea area for EnQuest, said, “In the northern North Sea we’re the only people drilling. People are decommissioning and abandoning, but we’re the only ones making invest-ments in the northern North Sea, and we’re doing that very successfully.

“We’re a lot more streamlined and agile than a supermajor. Everybody wants to know how we do it.”

Apache continues Forties, Beryl workCory Loegering, managing director of another nimble North Sea producer, Apache, said his firm has two of the most prolific North Sea hydrocarbon accumula-tions at Forties and Beryl.

Forties was acquired in April 2003 from BP for $630 million, and Apache has since invested $2.3 billion in infrastructure and another $2.3 billion on drilling and workovers.

The Beryl area was bought in January 2012 from Exxon Mobil for $1.44 billion, and $300 million has since been spent on infrastructure.

Apache describes itself as an industry leader for operating costs in the North Sea. Its operating costs per barrel were $13.62 in 2015.

Loegering said Apache will be spending more of its capital on drilling in the future. In 2012 to 2015, the company allocated 51% of capital on drilling and completion, but this is due to jump to 78% during 2016 to 2020.

Inevitably, there have been some delays to projects in the wake of the oil price crunch, and Statoil has pushed production startup on its Mariner Field out to 2017. The average production is estimated at about 55 Mbbl/d of oil over the plateau period from 2017 to 2020.

Expected recoverable oil volumes are estimated at more than 250 MMbbl.

The field will be developed with a production, drill-ing and quarters platform based on a steel jacket with 50 active well slots and a floating storage unit of 850 Mbbl capacity.

There is plenty of activity planned in the U.K. North Sea in 2016 and beyond, but the industry will have to continue to raise its game to ensure it has a glob-ally competitive and efficient base that continues to attract investment.

Michie added, “Even in these challenging times, we continue to have a supply chain that is the envy of the rest of the world as a center of excellence for offshore technologies. The supply chain generates tens of bil-lions of pounds in domestic and export sales. It has a workforce with expertise that is unsurpassed globally and whose skills will be critical in helping us unlock the remaining barrels on the U.K. Continental Shelf. With up to 20 billion barrels of oil and gas estimated still to recover, there is good opportunity ahead.” n

BATTLE AHEAD (continued from page 8)

“We’re a lot more streamlined and agile than a supermajor. Every-body wants to know how we do it.”

—John Cowie, EnQuest

The country is currently wholly dependent on 100% of oil exports and was only recently reliant on up to 90% of gas exports. Since the Corrib Field began flowing on New Year’s Eve 2015, only about 35% of gas has been imported, Carroll said.

Carroll said that up to 2050, the domestic demand for electricity and transportation would force fossil fuel dominance for a long time, with gas supplying the electric sector and oil fueling transportation. As a member of the EU, Ireland is connected to its energy market, which is worth 400 bil-lion euros (US$460 billion).

While it has the latest industry technologies at hand, Ireland’s E&P industry also has the support of the government, as evidenced both by the 2015 licensing round and by initiatives dedicated to supporting exploration, such as the Irish Centre for Research in Applied Geosciences (iCRAG), that serve the E&P sector. Carroll said part of the government’s role is to maintain a framework for the industry that pro-vides technological, safety and envi-ronmental regulation. n

IRELAND (continued from page 13)

The Glen Lyon FPSO vessel will operate on BP’s Quad 204 project. (Photo courtesy of Halvorsen)


agement approaches from the aeronautics industry to inform stakeholders and further strengthen worker and environmental safety protections on the Outer Conti-nental Shelf.

Kaplan proposed the scenario where an operator of an offshore rig had three different pumps from the same lot and same vendor but used on three different systems under dif-ferent managers on the rig.

“When one fails, you immediately have to ask the question, ‘Could there be a sys-tematic problem with that?’” he said.

The use of the other systems in this sce-nario would immediately put the rig at risk. Adoption of the PRA technique would call the risk to each manager’s attention, he said.

“A system manager can understand their system incredibly well, but it’s really impos-sible to fully understand the complete integrated set of operations occurring on a complex facility,” he said. “Trust me; our astronauts are very smart people. There is no way without mission control that they would be able to stay onboard the space station.”

Under the agreement, NASA will assist BSEE in achieving three primary objectives:

• Further develop BSEE’s risk manage-ment capability through the use of NASA’s PRA technique;

• Evaluate, design and test technologies and hardware, including emerging technologies and best available and safest technologies; and

• Assess failures and near miss occur-rences using the resources and ex-pertise of NASA’s accredited failure

analysis laboratory at the Johnson Space Center in Houston.

NASA also entered into an agreement with Anadarko Petroleum Corp. about a year ago to evaluate the PRA on a BOP. The partnership’s results will be made avail-

able to the American Petroleum Institute and BSEE, Kaplan said.

“Anadarko brings expertise with BOP—I would know noth-ing about a BOP, I know a lot of about shuttle engines but not BOPs—to sit side-by-side with NASA PRA experts,” he said. n

NASA (continued from page 7)

GOAL (continued from page 1)

range, greenfield developments have been more dif-ficult, Joe Geagea, Chevron’s executive vice president of technology, projects and services said in a May 1 conference call.

“Obviously we need scale in the resource, but we also need to rethink about how we bring our development,” Geagea said.

Chevron is considering optimizing development concepts.

“This is another place where we actually need our sup-pliers,” he said. “We need to work closely with them to continue to drive the cost down.”

Kraly said the complexity of projects is increasingly a hurdle, one that has it bringing aspects of engineering back inside the company; working closely with suppli-ers toward standardization and even reworking the basic metallurgy it uses.

Chevron measures its ability to successfully manage a project using the International Project Agreement stan-dards of schedule, cost and production attainment—reaching Chevron’s prediction of first year production.

Among selected projects, Kraly said cost and sched-ule problems, which often are intertwined, disrupted many projects.

“At the very end, only 8% [of projects] meet cost, schedule and production attainment. From an industry perspective is probably why we’re here today,” he said.

Adjustments are essential, Kraly said. “If we don’t change, obviously in this low price environ-

ment many projects are not going to be viable,” he said. Kraly, sounding somewhat like a coach, said Chevron

and other deepwater drillers have to come together, inno-vate and return to basics.

“We have to do what Leicester City has done, go back to basics, back to what you do fundamentally to be really ultimately successful,” he said. n

tional spend. And if Mexico begins to develop its shale resources, it will require a large number of rigs.

“It depends on the E&P companies, their infrastruc-ture plans and needs, and their appetite for risk,” he said.

Sergio Aceves, vice president of business develop-ment for DIAVAZ, agreed that the energy reform ini-tiative is one of the most ambitious and comprehensive of its kind. “It sets the stage for new infrastructure,” he said. “It’s meant to motivate the private sector.”

Despite a sluggish start, he added, the reform is resulting in a great deal of interest in Mexico’s resource potential. The last bidding round offered 25 onshore blocks, and all 25 received bids. But the full transition will take time.

“I see a lot of potential for the service sector,” he said. “Everybody’s learning. It’s not going as fast as everybody thought it would, but it’s going as fast as it can.” Low com-modity prices have not helped speed the pace, he added.

One benefit for the service sector is that a more open structure in the country will provide opportuni-ties for Mexican service companies such as DIAVAZ to partner with international companies, bringing technology and capital investment into the country.

Luis Escalante, general manager for FMC Technolo-gies Mexico, outlined some of the changes that service companies will have to contend with. Prior to the reform

measures, they only had one client, one standard contract model for each type of service, multiannual contracts per geographical area, highly commoditized requirements, direct contract awards and standard terms and conditions. The multiannual contracts meant that typically contracts were renewed every year without the contractor needing to renegotiate or go out for bid.

Since the reform, Mexico already has 18 new play-ers and is likely to get more as its bid rounds continue. Round 1.4, which will entail deepwater blocks, is offering up 10 blocks, Escalante said, and already 29 companies have shown interest. Round 1.5 will offer up the first of the shale blocks.

“There will be a lot of new players in this market,” he said.

His suggestions for success were many. Service compa-nies will need to:

• Migrate their culture to accommodate multiple customers;

• Increase their portfolio through an integrated pack-age offering;

• Expand locations to be closer to clients;• Move to multifunctional teams;• Adapt to different contract terms and conditions;• Optimize supply chains;• Develop local capabilities;• Improve their culture of innovation;• Consider partnerships for technology develop-

ment; and• Provide customized solutions. “You have to be very competitive to be successful in

Mexico,” he said. n

Left to right: Luis Escalante, Sergio Acevez, Francisco Mendez and Iain Cook spoke during the technical ses-sion, “Mexico Energy Reform II: Changes to the Service Sector and First Look at New Deepwater Plays Seen in New Multiclient Exploration Data.” The session mod-erators were Francisco Mendez, Mayer Brown and Paul Mann. (Photo by CorporateEventImages.com)

CHALLENGES (continued from page 1)


CONTRIBUTED BY WELLTEC

The Welltec Annular Barrier (WAB) is an expandable, metal barrier that can be used for several applica-

tions, including well integrity, zonal isolation or cement assurance. Last year, the WAB won the OTC Spotlight on New Technology for its ability to be deployed as a pri-mary well barrier, preventing surface annular pressure and sustained casing pressure.

The WAB provides an annular well barrier for zonal isolation between reservoir units or to prevent pressure migration to surface when run shallow of the caprock. The WAB delivers a surface controlled, rugged, reliable, high expansion annular barrier that delivers high-pres-sure capability covering a large hole range (full Delta P capability from the drilled hole size out to a worst case washed out hole scenario). The company was qualified in accordance with the IS014310 V3 standard and to the V0 leak criteria for application for cased hole environments. Further, the WAB has been deployed as a standalone pri-mary well barrier (i.e., no cement) in compliance with NORSOK D-010 Rev 4 standard.

Case study from NorwayAn operator was experiencing major challenges in posi-tioning the 9⅝-in. production casing shoe within the top of a heavily depleted reservoir. The low pore pres-sure in the depleted zone had repeatedly caused severe losses during the cementing operation, which resulted in difficulties to construct a primary barrier using

cement within the 9⅝-in. to 12¼-in. annulus. Many solutions had been trialed with varying degrees of suc-cess; the majority resulted in reliance upon contingency plans, bringing increased cost and risk. The WAB pro-vided the technological solution required by being able to provide a 5,000-psi Delta P rating while running slick with an 11.37-in. outer diameter (OD), yet still opening to 13.8 in.

The WAB was assembled on the OD of the 9⅝-in. cas-ing string along with a third-party cement port collar, which was positioned just above it. The casing was run to depth without incident, the ruggedness of the WAB permitting liner rotation. Positioned about 15 m (50 ft) above the depleted zone, the primary cement job was completed with liner rotation, the cement plug bumped and pressure increased to expand the WAB, creating a successful primary barrier confirmed via pressure tests. Had the primary cement job not gone as planned, the port collar would have been opened and cement squeezed in on top of the WAB as a contingency, using it as a base.

Future developments More recently, in early 2016, Total E&P Congo pur-chased WABs as a completion component for the upcoming wells in their deepwater Moho Nord project. There they will be installed to achieve multiple barriers per well during the drilling and completion of the 17 wells planned for development of that field. The wells will be completed in water depths of 450 m to 1,200 m

(1,476 ft to 3,937 ft) producing from the Albian reservoir via a tension-leg platform.

Advances in materials and techniques have provided the industry an alternative to cement, one which can be success-fully applied to overcome a wide range of well challenges. The WAB promotes completion technology architecture, furthering the implementation of completion methods. n

BY VELDA ADDISION

When artificial intelligence technology inter-sects with abundant oil and gas seismic data,

the outcome could yield a more accurate depiction of what lies beneath the surface, enabling cash-strapped drillers to better target sweet spots and maximize returns.

It’s all based on algorithms that essentially teach com-puters how to solve complex problems—in this instance, how to quickly and accurately find subsurface faults that lead to lucrative hydrocarbon discoveries.

Naveen Rao, the CEO of two-year-old startup Nervana Systems, compared the concept to the brain and its network of neurons.

“Each neuron does a little bit of infor-mation processing. It combines that with the output of many other neurons, and the whole stack basically processes informa-tion that comes in through our sensors,” Rao told Hart Energy. “It’s eluded us on how to do that in a synthetic system or in a computer, but we’ve made some really big progress. All of these latest breakthroughs are based on artificial neuro networks,” or computational models inspired in design by the brain.

The Silicon Valley-based deep learn-ing, artificial intelligence company uti-lizes supervised learning when it trains or teaches the artificial neural network how to find oil and gas using data from geoseismic studies. A human with expertise gives examples of where oil and gas are typically found in a bunch of datasets. The network then learns how to detect the subsurface faults, recognizing data that are comparable to those given in the examples.

Overcoming Depleted Zones n Advances in materials and techniques have provided the industry an alternative to cement.

Artificial Intelligence Takes Shape In Oil, Gas Sector n Silicon Valley-based company helps operators target sweet spots, maximize returns.

A WAB is pictured going in hole. (Photo courtesy of Welltec)

See ARTIFICIAL INTELLIGENCE continued on page 23


does not recommend ongoing con-frontations with service companies because there is a limit to how much costs can be cut and rig rates are already down 30% to 40%.

“The operators are looking at where they can take out waste and focus on efficiencies,” she said. “I guess several years of $100 oil have made people less rigorous in the way that they look at their projects and in the way that they work. They are really focusing on being lean.”

Another aspect to consider is stan-dardization and simplification of equipment, which has the potential to mitigate 10% to 20% of costs.

Wilson advised players to take sev-eral new approaches. Among them:

• Be counter-cyclical. Locking in lower contract prices for long-term deepwater developments now—if balance sheets allow—will be advantageous later.

• Simplify and standardize to im-prove efficiency.

• Align objectives both internally and among operators and con-tractors/suppliers with clearly defined incentivized targets.

She also suggested sharing best practices across the industry to benefit all, although she acknowl-edged that the competitive nature of energy companies would require a shift in culture for that to succeed.

Wilson expects the recovery in oil prices to be accompanied by improved exploration performance, both in incremental and high-im-pact areas.

“Although we’re at the bottom of the cycle—we hope we’re at the bottom—we’ve been through this before, we can do it again,” she said. “We should come out stronger from this period, a little bit leaner but probably stronger.” n

DRILLING (continued from page 1)

ARTIFICIAL INTELLIGENCE (continued from page 22)

Information from the most expert humans is encap-sulated in an algorithm in a computer and applied over and over again, Rao said.

Nervana tested the proof of concept with Paradigm, which used Nervana Cloud to find subsurface faults and folds in 3-D seismic images.

“We approached Nervana Systems to explore ways artificial intelligence could help improve operational efficiency in oil exploration. Nervana successfully built a deep learning-based solution on their cloud to detect numerous subsurface faults within three-dimensional seismic imagery without the need for manual interven-tion,” Indy Chakrabarti, senior vice president of product management and strategy at Paradigm, said in a state-ment. “Nervana Cloud enables geoscientists to spend less time on repetitive tasks and become more productive.”

The concept can also be applied toward other goals. As described by Nervana, these include:

• Operational efficiency. By analyzing real-time data from sensors at drilling sites, operators can make adjustments to help drive production,

lower risk or preschedule downtime for equip-ment maintenance.

• Market prediction. Deep learning can also be used to help identify macroeconomic trends to guide E&P investment.

“AI has been around for a long time in some form or another. The goal has always been to recapitulate some of the capabilities that animals and humans have in a machine,” Rao said. “What has really occurred in the last couple of years has been the realization that we can actually do that for some particular tasks that were very hard to solve with computers. One of those big tasks is computer vision, the ability to look at an image or video on a camera and pick out meaning from that.”

The image or video could be of various types of data.“Our target is really a data scientist,” Rao said noting

Nervana provides a general platform for applying neuro networks to data problems faced by not only the energy sector, but also the health care, finance, retail, agriculture and technology industries among others. “A data scien-tist within an oil and gas organization can leverage our tools to be much, much more effective.”

Gaining efficiency and lowering costs have become the unofficial mantras of oil and gas companies during the latest downturn. As the supply-demand imbalance dragged down commodity prices and profits, many companies have turned to technology to improve operations.

When Nervana and Paradigm started the proof of concept, oil was between $50 and $60/bbl, Rao said. But it dipped below $30. A barrel of West Texas Intermediate crude was fetching $41.75 before noon (CT) April 20.

Today’s market conditions have curtailed some artifi-cial intelligence research efforts, Rao said.

“I do think that in some ways that kind of economic pressure helps because it pushes companies to be more forward-looking in terms of new technology to have a better bottom line,” he added. “When profits and margins are very, very high, you tend to see less innovation hap-pen because there is less competitive pressure to do so.”

However, companies are facing reality and seeking ways to make money in the field during difficult times, “using techniques like this as part of that solution,” Rao said. n

Plan now to attend the Arctic Technology Conference, an OTC event, Oct. 24 to 26, 2016 in Newfoundland and Labrador, Can-ada. Visit arctictechnologyconfer-ence.org for more information.

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