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ILFIELD TECHN

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JUNE 2016 JUNE 2016 JUNE 2016 EXPLORATION | DRILLING | PRODUCTION

OFC_OT_June_2016.indd 1 31/05/2016 08:47

ISSN 1757-2134

Contents June 2016 Volume 09 Issue 06

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NOV’s ReedHycalog™ Tektonic™ drill bits are tailored and optimised for your application, helping you achieve maximum efficiency.

Featuring advanced bit body geometry and the latest generation of PDC cutter technology, Tektonic drill bits increase your ROP, minimise NPT, and deliver lower cost-per-foot, improving the performance of your operation.

03 Comment

05 World news

10 Rising stars in Latin AmericaOilfield Technology correspondent, Gordon Cope, demonstrates that while low oil prices are putting many Latin American countries through the ringer, others are thriving.

14 Geophsyical sampling solutionsMarc Rocke, Polarcus, USA, reveals how sampling and survey efficiency has been improved through condensed shotpoint intervals, multiple sources, and removal of interfering shot energy in processing.

21 The evolution of hybridsAlex Wong, Shear Bits, Canada, highlights how new drill bit technology is improving wellbore economics.

25 Master your terrainAlexis Garcia, Brad Ivie and Andrew Miller, NOV, USA, introduce a new generation of PDC bits.

27 Refining bits for RSSAron Deen, Matt Case and Josh Criswell, Ulterra, highlight how customised bit development for RSS reduces tool failure.

31 Drilling with diamonds Bruno Cuillier, Aurelien Mangeny, Brad Takenaka and Danny Tilleman, Varel Oil & Gas Drill Bits, evaluate the performance of application-specific diamond impregnated bit designs in challenging drilling conditions.

35 Keeping it centralIain Levie, Antelope Oil Tools, USA, introduces a cost-effective solution for use in deepwater drilling.

37 Multilateral thinking Brian K Sidle, discusses developments in production logging tools for use in multilaterals.

43 Restoring well productivity Paul W. Bradley and Tom Sherwin, Well Flow International, Bahrain, explain how high density converters remove barite and scale to restore well productivity.

47 Parent well modellingBilu V. Cherian, Sanjel Corporation, Mathew Mcleary and Samuel Fluckiger, SM Energy, dicuss challanges of in-fill development.

51 Cutting chemcial costsPaul Wiseman, Bosque Systems, USA, shows how unbundling chemicals from the frack package gives producers more control and reduces costs.

53 Maximising production and asset lifeDr. David Horsup and Dr. Caleb Clark, Nalco Champion, USA, introduce a multi-functional technology designed to maximise water injectivity and oil production whilst extending asset integrity.

57 Advancing metocean dataJerome Cuny, Open Ocean, France, highlights the uses for sophisticated metocean forecasting and hindcasting in offshore oil and gas operations.

61 Tailoring trainingMark Bentley, AGR TRACS Training, UK, gives an insight into what to do when business dries up at home.

AXON X-BOP 4-CAVITY DUAL SHEAR DESIGN170,750 LBS [77,614 kg]

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AXON X-BOP w/ EXISTING STANDARD DOUBLE181,000 LBS [82,273 kg]

1

1

2

2

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A A

B B

INTERPRET DRAWING PER ANSI Y14.5ALL DIMENSIONS ARE IN INCHES.

ALL DIMENSIONS IN [ ] ARE MILLIMETERS, IN ( ) ARE REF.BREAK ALL SHARP EDGES TO .01-.03 x 45°

OR R.01-R.03.ALL BOLT HOLES TO STRADDLE COMMON

.X

.XX

.XXX

±.06±.02±.005

THIS DOCUMENT CONTAINS CONFIDENTIAL AND PROPRIETARYINFORMATION OF AXON. THIS DOCUMENT AND THE INFORMATION

DISCLOSED WITHIN SHALL NOT BE REPRODUCED IN ANY FORM,USED OR DISCLOSED TO OTHERS FOR ANY PURPOSE WITHOUT THE

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TOLERANCE AND FINISH

FRACTIONAL: ±1/16ANGULAR: ±3ºMACH. FINISH: 250

DWN: JWSCKD: WHAPP: WH

DATE: 2/15/2016DATE: 4/20/2016DATE: 4/20/2016

UNLESS OTHERWISE SPECIFIED MATERIAL AND HEAT TREAT:

TITLE:

18-3/4" 15M APIGA, AYAD DUAL SHEAR SOLUTION

SCALE: --- EST. WT: N/A SHT 1 OF 6

REV: ADWG: GA-3500-100002

LAST CHANGE NOTED BY: CONTAINING CURRENT REV. LEVEL

238.5[6059]

( )

238.0[6046]

( )

N/A

NOTES:1. DIMENSIONS, FEATURES AND WEIGHTS ARE APPROXIMATE AND SUBJECTTO CHANGE.

A --- 4/20/2016 INITIAL RELEASE WHREV ECN DATE DESCRIPTION APPR

AVAILABLE STACK CONFIGURATION COMPARISON

254.1[6454]

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1

1

2

2

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B B

TITLE:

18-3/4" 15M APIGA, AYAD DUAL SHEAR SOLUTION

SCALE: --- EST. WT: N/A SHT 2 OF 6

REV: ADWG: GA-3500-100002

270.2[6862]

( )

* Suitable for use in new or existingBOP stacks (including retrofits)

Comment June 2016

David Bizley, [email protected]

June 2016 Oilfield Technology | 3

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In an outcome rivalling the Earth’s orbit in terms of predictability, the OPEC meeting held on 2 June resulted in no change in policy; there will be no cap placed on oil production.

The main (and equally predictable) obstruction to any agreement appears to have been Iran’s refusal to do anything other than raise its output. The Islamic Republic is intent on returning to its pre-sanctions

level of production, much to the chagrin of other OPEC members straining to balance national budgets with oil prices hovering in the high US$40s. According to Reuters, Iranian Oil Minister Bijan Zanganeh said that Tehran had no interest in supporting any kind of collective production ceiling, arguing instead for individual production quotas for each member, “Without country quotas, OPEC cannot control anything” he said. Zanganeh went on to insist that, going by historic levels, Tehran was due a quota of 14.5% of OPEC’s total production, some 4.7 million bpd (from a total 32.5 million bpd), well above the country’s current output of 3.5 - 3.8 million bpd.

Saudi Arabia, OPEC’s de facto leader, was represented by its new Oil Minister, Khalid Al-Falih, who struck a different tone by pledging that the kingdom would be “very gentle in [its] approach and make sure [it didn’t] shock the market in any way.” When asked whether Saudi Arabia would bring more oil to the market, he said “there is no reason to expect that Saudi Arabia is going to go on a flooding campaign.” Al-Falih also pointed to the recent rising oil price and added that Saudi Arabia was “satisfied with the price movement over the last few months and think[s] it will continue to gently edge up without much intervention, assuming that more or less OPEC production stays where it is.”1 In other words: no change of policy.

Whilst this most recent meeting has provided few surprises, what it has shown is that OPEC no longer appears to as much control over oil prices as it used to. Al-Falih’s comments would suggest that everything is going as planned, but in truth there’s nothing Saudi Arabia can do to stop Iran raising its output and driving prices down again. Indeed, as long as Iran refuses accept what it sees as Saudi attempts to control its output, and Saudi Arabia refuses to go ahead without Iranian agreement, the deadlock will likely continue. A cartel that can’t agree on output isn’t much of a cartel.

Elsewhere in the oil-producing world, residents are finally beginning to return to Fort McMurray in Alberta, Canada after a massive fire caused some 90 000 people to be evacuated, and brought production in the Athabasca oilsands to a standstill. Reports have shown that some 500 homes have been declared unfit for human habitation, meaning that roughly 9000 people will be unable to return in the near future. Canada’s total oil output was temporarily cut by almost 25% as a result of the fire, which gave a modest boost to oil prices. Production in the Athabasca oilsands is now gradually ramping up again.

However, as one source of disruption begins to ebb away, another emerges. Nigeria’s oil output, long subject to corruption and pipeline sabotage, has suffered a further blow at the hands of the militant group known as the Niger Delta Avengers. The group, which claims to represent the local people and the environment, has targeted facilities at Chevron’s Escravos terminal and damaged the main power line, which has caused all onshore activities to be shut down. This attack and others have cut Nigeria’s oil output to 1.4 million bpd, down from 2.2 million bpd. This cut in output has placed significant strain on the finances of the country, which generates 60 - 70% of its revenue from oil exports.

All of this goes to show that the oil industry is truly global - events and political decisions on one side of the world can affect output on the other. Oilfield Technology looks at operations and technology from around the world; this issue is no exception, with articles covering operations across five continents. Get in touch if you’d like to take part.

References1. ‘Saudi Arabia’s Gesture for OPEC Unity Meets Iran Resistance’ - http://www.bloomberg.com/news/

articles/2016-06-02/saudi-arabia-s-gesture-for-opec-unity-meets-iranian-resistance

Go big, go Gigante.TGS gives you the right data, in the right place, at the right time. This time, it’s Offshore Mexico. The data has been consistently acquired and processed, and it’s complemented by interpretation, multibeam and seafloor sampling analysis. The latest, most comprehensive view of the region’s potential. See it here.

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© 2016 TGS-NOPEC Geophysical Company ASA. All rights reserved.

World news June 2016

In brief


Technip receives major natural gas field development contract in Central Mediterranean SeaTechnip has received a major contract to develop the Bahr Essalam, Phase II development in the Central Mediterranean Sea.

This natural gas field development is operated by Mellitah Oil & Gas B.V. Libyan Branch.The overall scope of work will see Technip perform the design, detailed engineering

and deliver the project management, as well as procurement, installation, tie-ins, pre-commissioning and commissioning. This will be associated with the provision of a gas gathering system, comprised of production pipelines, subsea isolation valve (SSIV), umbilicals, as well as extensive diving and installation campaigns. It will also include modifications to the Sabratha platform regarding the topsides. All offshore mobilisations will be undertaken from Malta.

Offshore installation is scheduled for 2H17 through to 2H18.Thierry Pilenko, Chairman and CEO, commented: “We are proud of this contract award,

which is a strong recognition of Technip’s broad capabilities across a variety of areas. It is also testament to our team’s ability to adapt to the challenging market environment, and to provide solutions that still enable field developments. We very much look forward to working with Mellitah to safely and successfully deliver this large project, by leveraging our strong know-how and experience in high-quality product manufacturing and subsea installation.”

In addition, Technip confirms the renewal of the charter for its Skandi Vitoria vessel in Brazil and the expansion of its contracted work outside backlog also through a large contract.

Sembcorp Marine delivers jack-up for Culzean projectSembcorp Marine has delivered the high-specification jack-up rig Maersk Highlander (formerly known as Hercules Highlander) to Maersk Highlander UK Ltd.

The Maersk Highlander is constructed based on the Friede & Goldman JU 2000E design and is fully compliant with UK HSE standards. It is well suited for harsh-environment operations and will be deployed in the Culzean Field Development, located in the UK sector of the North Sea.

As a heavy-duty offshore drilling asset, the Maersk Highlander can operate in water depths of up to 400 ft and drill to 30 000 ft. Its capabilities include a 2 million lb drilling capacity, 6000 bbls of mud capacity, 28 000 kip preload capacity for the legs, and an accommodation facility that houses up to 150 workers.

The rig’s construction started in September 2014 and was completed on schedule with a safety record of zero near-misses and reportable cases.

NPD grants drilling permits for Statoil wellsThe Norwegian Petroleum Directorate (NPD) has granted Statoil Petroleum AS a drilling permit for wells 30/11-14, 30/11-14 A and 30/11-14 B.

The three wells will be drilled from the Songa Delta drilling facility at position 60˚11’29.9’’ north and 02˚35’11.4’’ east in production licence 035.

The drilling programme relates to the drilling of two wildcat wells (30/11-14 and 30/11-14 B) and one appraisal well (30/11-14 A) which will be drilled if a discovery is made. Statoil is the operator with an ownership interest of 50%. Det norske oljeselskap ASA is the licensee with a 50% stake.

The area in this licence consists of a part of block 30/11. Production licence 035 was awarded in licensing round 2-A on 14 November 1969. These are the 12th, 13th, and possibly the 14th exploration wells to be drilled within the licence area.

Iraq Genel Energy plc has noted the announcement from DNO ASA, as operator of the Tawke field, that the Tawke field partners have received a payment of US$16 million from the Kurdistan Regional Government for oil sales during April 2016.

The payment reflects part settlement of the invoiced amount of US$32.3 million for April 2016 Tawke oil sales. This figure incorporates US$27.1 million towards contractor monthly entitlement and US$5.2 million towards recovery of historical receivables.

Tawke production in April averaged 118 918 bpd, of which 117 815 bpd were earmarked for export, up from an average of 74 546 bpd in March.

Canada Residents are due to start returning to Fort McMurray in North-West Canada after a wildfire displaced some 90 000 people.

According to the BBC, 500 homes across several neighbourhoods had been deemed unsafe for habitation, meaning that roughly 9000 people would be unable to return in the immediate future.

Fort McMurray is situated in the state of Alberta, next door to the state’s oil sands. The fire brought production to a halt, cutting Canada’s total oil output by almost 25%.

Israel The partners in Israel’s Leviathan gas field have signed a deal to supply up to US$3 billion worth of gas to a power plant in central Israel.

Under the agreement, once production begins, the field will provide 13 billion m3 of gas over 18 years. Leviathan was discovered in 2010 and holds 622 billion m3 of gas reserves.

6 | Oilfield Technology June 2016

World newsJune 2016

Diary dates

To read more about these articles and for more event listings go to:

Web news highlights

www.oilfieldtechnology.com

ÌÌ Next Geosolutions awarded multiple industry accreditations

ÌÌ Iran and India sign MoU to develop Farzad B

ÌÌ Voith and Fuglesangs Subsea introduce topside-less solution for subsea boosting

ÌÌ First Geo wins Det norske contract

Statoil’s Heimdal field turns 30The Hemidal field, located in the Norwegian North Sea, has been an important supplier of gas to Europe for the last 30 years.

The production licence for the field was first granted to Pan Ocean Group in 1971. The first well, which was drilled between July and December 1972, revealed both gas and condensate reserves.

When production began in late 1985, Heimdal was the largest steel jacket on the Norwegian continental shelf. The field produced gas and condensate at steady rates from 1986 to 1996. As production began to decline, plans were drawn up to use Heimdal as a transit and processing centre for other fields. Heimdal now receives and processes gas from fields such as Huldra, Oseberg, Skirne and Vale.

Nina Birgitte Koch, VP for operations for Heimdal, said “Heimdal has played an important role in Norwegian petroleum history”.

SKE makes significant gas find offshore MalaysiaSapuraKencana Energy (SKE) has announced another significant gas discovery from its three wells 2015 drilling campaign within the Block SK408 Production Sharing Contract (PSC) area, offshore Malaysia.

All three wells targeted non-associated gas within the primary target Late Miocene Carbonate reservoirs. The first well, Jerun-1 is a significant discovery located approximately 5 km north of the 2014 Bakong gas discovery.

Based on analysis of electric log, pressure and sample data Jerun-1 has an interpreted gross gas column of approximately 800 m in the primary target reservoir and is a multi-TCF gas discovery. Jeremin-1, located approximately 15 km west of the F9 gas field encountered a 104 m gross gas column.

Putat-1, located approximately 20 km north of the Cili Padi gas field is confirmed as a dry hole. All wells have been safely plugged and abandoned.

19 - 22 June, 2016

AAPG ACECalgary, CanadaE: [email protected]

01 - 03 August, 2016

URTeCSan Antonio, USAE: [email protected]

29 August - 01 September, 2016

ONSStavanger, NorwayE: [email protected]

26 - 28 September, 2016

SPE ATCEDubai, UAEE: [email protected]/atce/2016

24 - 27 October, 2016

Rio Oil & GasRio De Janiero, BrazilE: [email protected]/en

DOF Subsea in GoM and North Sea dealsDOF Subsea has been awarded several ROV and diving contracts for the vessel Skandi Achiever in the North Sea and the North America region, securing utilisation of the vessel until end-October 2016.

Following completion of ongoing commitments in the North Sea, the vessel will mobilise to Canada for ROV and light construction activities with a major operator before transiting to the GoM to support saturation and surface diving projects.

In Brazil, Petrobras has awarded a new contract for the vessel Skandi Vitória securing utilisation for the remainder of 2016. The vessel is owned through a joint venture together with Technip.

Mons S. Aase, CEO, stated, “I am very pleased with the contract awards, and our global organisation’s ability to secure utilisation in a challenging market.”

Subsea 7 terminates contract offshore BrazilSubsea 7, the global contractor supplying seabed-to-surface engineering, construction and services to the offshore energy industry, has announced the early termination of the day-rate contract for the company’s pipelay support vessel (PLSV), Seven Mar, working for Petrobras, offshore Brazil, effective as of 31 May.

The contract was due to expire at the end of 2016 and, as a result, the group backlog has diminished by approximately US$47 million.

The cancellation of the contract was brought about by Brazilian maritime law, which prioritises Brazilian-flagged vessels over international vessels of a similar specification. As a consequence, the operating licence for Seven Mar has expired, which resulted in the early termination of the contract.

June 2016

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June 2016World news


First cargo of Yamal oil shipped from Arctic gate terminalThe year round shipments of Yamal oil from the Arctic Gate (Vorota Arktilo), an Arctic loading terminal, were marked by an event which took place on 25 May in the Mys Kamenny settlement (Yamal Peninsula, Yamal-Nenets Autonomous Area). The event was attended by Alexey Miller, Chairman of the Gazprom Management Committee, and Alexander Dyukov, Chief Executive Officer of Gazprom Neft.

It was via videocall that Russian President Vladimir Putin gave the command to start loading a tanker with oil from the Novoportovskoye field.

The Novoportovskoye oil, gas and condensate field, the richest in oil reserves in the Yamal Peninsula, is located 700 km away from the existing pipeline infrastructure. That is why it was decided to ship Yamal oil by sea for the first time in history of Russia’s oil and gas industry.

Thanks to the technologies employed in building the production, transportation and, most importantly, loading infrastructure, it took only four years to arrange commercial oil production from the field. There are plans to extract 6.3 million t of feedstock from the field as early as 2018. The plan for further field development will be outlined before late 2017.A pipeline over 100 km long transports oil from the Novoportovskoye field to the Ob Bay coast. The bay’s ship channel with a depth of 11 m is too shallow for ship traffic, which is why the oil loading terminal was placed in the sea, 3.5 km offshore. The annual capacity of the oil transshipment terminal is up to 8.5 million t. The terminal ensures a year round landing of tankers with Yamail oil for further shipments via the Northern Sea Route. According to Alex Miller, Chairman of the Gazprom Management Committee, “Gazprom is systematically exploring the Russian Arctic. We are successfully extracting oil from the Prirazlomnye field, Russia’s only hydrocarbon production project on the Arctic shelf. We have opened the Arctic Gate to deliver Yamal oil to European consumers via the Northern Sea Route all year round.”

GE Oil & Gas to use 3D printing and robotics Two new high-tech component production lines have been inaugurated at the GE Oil & Gas plant in Talamona, Italy. The new nozzle production line marks the first completely automated line for GE, and a new additive manufacturing line will use laser technology to 3D print burners for gas turbine combustion chambers. These new advanced manufacturing lines establishes this site as a centre of excellence for the oil and gas industry.

The official unveiling of the upgraded turbine and compressor components manufacturing facility is the result of a €10 million, two year investment to establish the plant as one of its most cutting production centres. Previous investments in 2013 increased the plant’s production capacity.

With this new line, GE Oil & Gas will be able to produce components in Talamona that it previously purchased from third-party suppliers.

KOC awards Amec Foster Wheeler FEED contract Amec Foster Wheeler has announced that it has been awarded a FEED contract by Kuwait Oil Company (KOC) to upgrade its Oil Gathering Centre GC-24.

This project sees a continuation of Amec Foster Wheeler’s work with KOC on major projects since 2004, which has recently included three new Gathering Centres and strategic pipeline projects in North Kuwait.

Roberto Penno, Amec Foster Wheeler’s Group President said, “Kuwait Oil Company is one of our key customers and this further strengthening of our working partnership follows our success in delivering projects for them and management of the original GC-24 Project.”

Critical to the expansion, this project will enhance the existing GC-24 facility, increasing capacity by 50 000 bpd from the current level of 165 000 bpd and optimise existing facilities to cater for the expected high level of water in the mix of crude oil and gas.

Shell buys award-winning subsea pump upgrade Sulzer and FMC Technologies have been awarded a subsea multiphase boosting pump contract to upgrade one of the pumping modules in Shell’s Parque das Conchas, a deepwater oilfield off the coast of Brazil. The pump modifications suit the specifics of the oilfield with a high shut-in pressure of 517 bar (7500 psi), meeting Shell’s maintenance and service needs with high reliability and short turnaround intervention.

A key part of the success of the project has been the collaboration between Shell, FMC Technologies, and Sulzer. The pump will be manufactured from a global supply chain.

The first subsea pump for Shell from FMC Technologies and Sulzer will be launched in the field in 2017. It will demonstrate the pump’s capability to maintain yield levels and achieve excellent reliability targets in the harsh deep-sea environments.

Bibby Offshore awarded North Sea contract Bibby Offshore has announced a substantial contract win with Apache North Sea Ltd to provide subsea construction, ROV and diving services at the largest oilfield in the North Sea.

The contract, due to begin this month, will utilise Bibby Offshore’s multi role diving support vessel the Bibby Topaz, equipped with an inspection class ROV.

The project, which involves well tie-ins and spool change-out at the Aviat and Bacchus locations, along with the associated pre-commissioning works, will be conducted to tie back the subsea wells to the Forties Oil Field, 110 miles east of Aberdeen.

Fraser Moonie, chief operating officer at Bibby Offshore said, “We are delighted to have secured another North Sea contract and to be working wit the Apache North Sea team again, further strengthening our relationship.”

June 2016

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RISING STARS IN LATIN AMERICA

OILFIELD TECHNOLOGY CORRESPONDENT, GORDON COPE, DEMONSTRATES THAT WHILE LOW OIL PRICES ARE PUTTING MANY LATIN AMERICAN COUNTRIES THROUGH THE RINGER, OTHERS ARE

THRIVING.

10 |

Inguazu Falls, Argentina

Many countries in Latin America are blessed with an abundance of oil and gas. According to the US Energy Information Administration (EIA),

Latin America (the South American continent and Mexico), holds a total of 340 billion bbls of proven crude reserves and production exceeding 7 million bpd. The region also had a total of 277 trillion ft3 of conventional gas reserves and produced slightly over 16.3 billion ft3/d in 2013.

And while no country has escaped the recent pressures of low commodity prices, some have fared far better than others. Who is winning – and who is losing – largely depends on how central governments have promoted (or impeded), the sector.

| 11


MexicoMexico offers the most intriguing opportunities in all of Latin America. Under President Enrique Peña Nieto, federal reforms have eliminated Pemex’s monopoly. Oil firms are being allowed to participate in exploration and production, as well as direct private investment in midstream and downstream sectors. The potential is huge; in addition to 10 billion bbls of proven crude reserves (and 2.3 million bpd production) the country has over 17 trillion ft3 of proven gas reserves. Also, the unconventional oil and gas revolution that has taken place in Texas extends across the Rio Grande into Mexico; the EIA estimates that the country may hold as much as 555 trillion ft3 of recoverable shale gas.

Mexico has already held several lease auctions. Participation in the first round was relatively muted (partly due to low oil prices, and partly due to growing pains at CNH, the federal agency overseeing privatisation), but the action has picked up. Mexico has awarded three out of five offshore production sharing contracts in the second round, and all 25 blocks of producing, land-based assets were picked up in the third round.

Still to come later this year; bidding rounds for shale oil and gas fields, as well as 10 deepwater blocks in the Gulf of Mexico. Four of the blocks are located adjacent to the prolific Perdido Fold Belt, in which majors such as Shell and BP have developed a host of prolific fields. Analysts estimate that the Mexican portion of the belt could hold 15 - 20 billion bbls of recoverable oil.

Pemex, which will continue to be the dominant player in Mexico’s O&G sector for many years to come, faces significant challenges. After years of functioning as the federal government’s piggy-bank, it is now strapped for cash. In addition to US$100 billion in corporate debt, the company also owes US$7 billion to service providers. It has scrambled to cut costs, including deferring US$4 billion in capital projects and US$1.6 billion in efficiencies. In addition, it is negotiating with its 100 000 union members to control labour costs.

Regardless, Moody’s downgraded the oil behemoth’s credit rating to two rungs above junk. Industry observers are concerned whether it will be able to access sufficient capital to meet its host of JV and deepwater exploration commitments under the new open regime. Others are speculating that the oil giant may be forced to divest itself of significant upstream, midstream and downstream assets in order to avoid insolvency.

On the plus side, Mexico is taking corruption allegations seriously, putting in transparent O&G regulations and policies. The federal government is committed to reversing the downward production trend for both oil and gas, and increasing revenues.

And, thanks to modern seismic, Pemex has also discovered four new shallow-water oilfields off Tabasco and Campeche states, holding as much as 350 million recoverable boe. They are the first major discoveries in the post-reform period, and could add as much as 200 000 bpd of crude output in a relatively short time span.

Mexico hopes to eventually reach 3.5 million bpd production by 2025. Analysts estimate that it would take annual O&G sector investment of US$15 billion, or US$150 billion in total, to reach that target. While no one doubts there are many challenges ahead, the country can be lauded for the immense reforms that have already been successfully achieved, with many more to come.

Colombia Colombia serves as a shining example of how a country can turn its O&G sector around. During the late 1990s, a lack of investment, hostilities with FARC guerrillas, and a generally hostile attitude toward international investment had cut the country’s 990 000 bpd output in half. Following a series of fiscal and regulatory changes in 2003 under the Uribe government, the sector was opened up to privatisation. Since then, investments exceeding US$5 billion annually have resulted in a rise

in production to 1 million bpd, with the majority of new production earmarked for export to the US, China and Europe.

Even with the current low commodity price regime, Colombia continues to make headway. Petrobras made a significant gas discovery in the country’s deepwater Caribbean Sea. Ecopetrol and JV partner Anadarko discovered a nearby natural gas field in their shallow water Fuerte Sur block. The exploration well, situated 53 km offshore, encountered up to 70 m net pay of porous sandstones. Geopark discovered heavy oil in its Jacana prospect near the large Tigana oilfield in the Llanos basin. The Jacana 1 exploration well flowed 1880 bpd of 15 API gravity oil. A second well flowed 1100 bpd of 30 API oil from a different formation.

Resistance groups like FARC remain a problem, however. Attacks upon pipelines have exceeded 100 annually for the last several years, eliminating approximately 45 000 bpd through unplanned production outages. In March, US Secretary of State John Kerry met with FARC representatives in Havana in order to facilitate talks, but until peace negotiations succeed, industry observers expect production growth in Colombia to slow significantly.

ArgentinaArgentina’s ham-fisted approach to the O&G sector over the last decade has resulted in destructive consequences. Production has fallen from over 900 000 bpd in 1998 to current levels of 523 000 bpd, and gas from 4.5 billion ft3/d in 2007 to 3.5 billion ft3/d. The nationalisation of Repsol’s subsidiary YPF was a particularly egregious blow; in 2012, President Cristina Fernandez de Kirchner seized control of the busiest explorer in the country.

A bright note in Argentina’s favour is its unconventional potential. The EIA estimates that the country could contain up to 774 trillion ft3 of recoverable shale gas and 21 billion bbls of shale oil, mostly in the Vaca Meurta formation in the Neuquen basin in western-central Argentina.

Even with the nationalisation of YPF, several international players have stepped in to invest. Sinopec has partnered with YPF to explore a region in the western Argentine province of Mendoza. The US$300 million JV includes 3D seismic surveys, wildcat wells and the refurbishment of existing infrastructure. German-based Wintershall plans to drill up to six horizontal wells in its Neuquen province block to test the potential of the Vaca Muerta.

By early 2016, the Vaca Muerta was producing 50 000 boe/d (mostly oil). YPF and Chevron are major JV players, accounting for more than 90% of the production. Low crude oil prices have put some of their exploration plans on hold, but work is underway to reduce costs per well from US$16 million to US$10 million. YPF estimates that it will take up to US$200 billion in oil shale investments to reverse the country’s declining oil production.

Although below-ground prospects are good, the political and financial realms remain uncertain. President Kirchner has been replaced by Mauricio Macri (who ran on a platform of economic reform), but massive debts, low growth and a stunted economy remain. Argentina has taken some steps to encourage international investment; a new policy features a reformed bidding process, more numerous offshore licensing rounds, longer exploration periods and tax exemptions to companies that invest more than US$250 million over a three year period.

Argentina’s offshore potential, which could match Brazil’s, has been complicated by an ongoing feud with the UK. In 2015, the Argentine government filed a suit against five energy companies that are drilling near the Falkland Islands, including UK’s Rockhopper Exploration, Premier Oil and Falkland O&G, as well as US company Noble Energy and Italy’s Edison International. An Argentine judge subsequently ordered the seizure of assets totalling US$156 million (Most of the companies


do not generally hold any assets in Argentina, or navigate in Argentine controlled waters).

VenezuelaAccording to the EIA, Venezuela has 298 billion bbls of proved oil reserves, the largest in the world, exceeding Saudi Arabia (268 billion bbls) and Canada (173 billion bbls). Venezuela also has, arguably, the most dysfunctional oil sector in all of South America. Under its former leader, President Hugo Chavez, several major projects in the prolific heavy oil belt were nationalised, PDVSA’s geoscience and engineering corps were purged, and the national oil company’s coffers plundered. Production fell from a high of 3.5 million bpd in 1999, to an estimated 2.6 million bpd in 2014.

PDVSA’s current difficulties highlight the calamity unfolding in the O&G sector. Financial statements for 2015 note that PDVSA’s total financial debt stood at US$43.9 billion, and debt to suppliers stood at US$20 billion. Moody’s downgraded PDVSA’s credit rating, citing a higher probability of default or debt restructure in the next twelve to eighteen months due to low cash generation and a lack of visibility regarding the company’s investing and refinancing plans.

In a scramble for more cash, PDVSA is abandoning energy agreements made with neighbouring countries. Under former president Hugo Chavez, Venezuela agreed to supply crude and refined product at reduced prices. Payment could be delayed for up to two years, or met via barter. Uruguay, Jamaica and the Dominican Republic have been constrained to buy shipments on the spot market to make up for shortfalls.

Because Venezuelan petroleum is dominated by heavy crude from the Orinoco belt, the country has been importing lighter crudes and condensate to blend with its output. International cash flow from crude sales, which has dropped almost US$40 billion since the fall in commodity prices, has meant late payments from PDVSA. Several oil suppliers are now requiring prepayment before discharging shipments. Shell, Statoil and Total are among suppliers who delivered 13 cargoes at the Bullenbay terminal on the island of Curacao during 2015; several ships were significantly delayed by payment disputes. Venezuela’s crude is in demand from refineries in the Gulf Coast region, however, and BP and China Oil have been arranging swap deals of refined products in order to access the heavy oil for export.

PDVSA’s problems extend well beyond the financial realm. In late 2015, the US Justice Department charged Roberto Rincon, a Venezuelan resident residing in Texas. Officials allege that Rincon and others conspired to pay bribes in order to arrange contracts with PDVSA. Between 2009 and 2014, several millions of dollars were paid to PDVSA officials in order to obtain work and services valued at over US$1 billion. One of the conspirators and three PDVSA officials have pled guilty so far. The US Department of the Treasury also alleges that PDVSA has laundered US$2 billion in funds through an Andorran bank. Opposition politicians state that corruption in the state firm may have costs Venezuelans up to US$10 billion.

Not all is bleak; Rosneft, Russia’s top oil producer, is heavily involved in joint ventures with PDVSA in the Orinoco belt in an effort to turn production declines around. Early in 2016, Rosneft and PDVSA also set up a JV to develop Venezuela’s offshore natural gas potential. Three fields will produce approximately 9 billion m3 annually, enough to feed an export pipeline or LNG project.

BrazilBrazil is both blessed with natural resources and cursed with greed and corruption. Thanks to the immense resources of the offshore subsalt play, Brazil’s output has risen to 2.25 million bpd and 2 billion ft3/d of gas.

Hardly a month goes by without an announcement of a new discovery. In early 2016, new exploratory wells confirmed that the Carcara presalt discovery extends well beyond original boundaries.

The initial prospect well, drilled in 2012, encountered 400 m of continuous light oil. The latest well, called Carcara NW, encountered oil with a similar pressure profile 5.5 km northwest of the first well. Although recoverable oil estimates for Carcara have yet to be published, there is little doubt that it will add significantly to recent discoveries. According to federal authorities, of all the oil discovered around the world in the last five years, 36%, or 23 billion bbls, has been found in Brazil.

In addition, much headway has been made in bringing the subsalt play into production. In early 2016, the Lula Alto area of the Lula Field, situated in the Santos basin presalt, entered production when the Cidad de Marica FPSO was anchored in 2120 m of water. The vessel is connected to 10 production wells, and has the ability to produce 150 000 bpd. This is the fifth FPSO installed in the field; in all, Petrobras now produces over 1 million bpd from presalt.

Yet Petrobras is in serious financial difficulties. The company reported a 2015 net loss of US$9.7 billion, up from a US$6 billion loss in 2014. Petrobras has over US$130 billion in debt, and has slashed its budget and shed approximately 1500 non-operational managerial positions. It will also sell core and non-core assets worth US$15.1 billion, including part of its stake in the huge Libra offshore prospect.

In addition, the company is hobbled by a serious corruption and kickback scandal. For over a year, federal investigators have been uncovering a massive scheme of chicanery that reaches up to the highest levels of government. As of late 2015, 87 people, including two former Petrobras directors, have been formally accused of offering and accepting approximately US$800 million in bribes and other inducements by inflating Petrobras contracts and funnelling part of the money back, including to the ruling Workers’ Party. Most recently, a federal judge sentenced Jorge Zelada, a former director of Petrobras international division, to 12 years in prison after finding him guilty of money-laundering and corruption.

The mess is having a domino effect within the sector. Moody’s has downgraded Petrobras to junk status, which denies the company access to international credit markets where it needs to raise over US$100 billion to develop the subsalt play. Its annual R&D budget has dropped from US$40 billion in 2013 to US$19 billion in 2016. Local contractors under investigation cannot seek new deals with Petrobras; many are going under because of unpaid bills.

No one knows how the situation will end; prosecutors were given Supreme Court permission to investigate senior politicians and promptly brought former-president Luiz Inácio Lula da Silva in for questioning. Even the current President, Dilma Rousseff, has not escaped unscathed: she is currently suspended from office whilst impeachment proceedings are carried out. In early February, a Manhattan judge ordered Petrobras to face class-action litigation from investors who are seeking to recoup billions in losses due to the bribery and political kickbacks scandal. They claim that the company inflated its value of its stocks and bonds by more than US$98 billion.

Various steps are being taken to rectify Brazil’s dysfunctional O&G sector. In late February, federal lawmakers introduced legislation that would remove requirements that Petrobras hold at least 30% interest in presalt blocks, and be the sole operator of presalt development projects. The move is seen as a response to lack of international interest in presalt licensing, and the scandal woes that are hindering Petrobras’ ability to take on further operational duties.

Conclusion Clearly, much still needs to be done to promote O&G in Latin America, but industry observers are taking heart in the concrete steps that are being taken by nations such as Mexico and Colombia. The current oil price slump is depressing activity, but international investors are well aware that the region remains one of the brightest stars in the O&G firmament.

GEOPHYSICAL SAMPLING SOLUTIONS

MARC ROCKE, POLARCUS, USA, REVEALS HOW SAMPLING AND SURVEY EFFICIENCY HAS BEEN

IMPROVED THROUGH CONDENSED SHOTPOINT INTERVALS, MULTIPLE

SOURCES, AND REMOVAL OF INTERFERING SHOT ENERGY IN

PROCESSING.

14 |

GEOPHYSICAL SAMPLING SOLUTIONS

Over the last 18 months Polarcus has been actively

acquiring surveys with condensed shotpoint intervals. A portion of this is the

XArray offering where condensed shotpoint intervals are leveraged across multiple sources

to achieve significantly improved cross-line CMP sampling when paired with currently available streamer

configurations. The solution has proven to be very flexible in responding to unique survey challenges, from achieving ultra-dense

6.25 m x 6.25 m real subsurface sampling, to maintaining optimum cross-line sampling when used with mega-wide spreads for maximum

efficiency. The acquisition technologies that make this technique possible are well established in the industry, however the company has tested, configured

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and successfully deployed them as a coherent means by which effective, tailored geophysical solutions are delivered. This article describes the implementation of XArray, the technical background behind the method and component technologies, and gives insight into some field examples.

With ever increasing pressure on E&P company budgets and often tight timelines to get from first shot to interpretable product, streamer spread dimensions have grown in size to achieve greater coverage per vessel pass while maintaining the trace density required to meet the geophysical objectives of the survey. On the data quality side, streamers themselves have gotten longer, targeting deeper reflectors while improving S/N gained from higher fold. Recording systems have in turn grown in capacity to keep pace with these increases in the size of towed receiver arrays, however the introduction of continuous recording functionality would arguably have just as significant an impact on the volume of data recorded per unit survey area and, by extension, acquisition efficiency and data density.

To demonstrate this, it is worth considering the limitations to the data acquisition process presented by the absence of continuous recording. Data acquired without using continuous recording is often referred to as being source initiation constrained, where the time between shots must be greater than the fixed record length for recording of that shot to occur. Thus deeper targets (longer record lengths) required sufficiently spaced shotpoint intervals to ensure that there was enough time between shots to capture the pre-set record length. As a result shotpoint interval/record length pairs of 18.75 m/7 seconds; 25 m/10 seconds; and 37.5 m/13 seconds in the case of wide azimuth acquisition became industry standard based on nominal vessel speeds. The advent of continuous recording however, enabled the decoupling of the frequency of source initiation from the record length captured. Firing several shots in the timeframe required to capture any one of the associated shot records is now entirely possible, making the standard shotpoint interval/record length pairs largely irrelevant from the perspective of what is technically achievable in acquisition. As an example, Polarcus recently acquired a survey where a source fired on average every 3 seconds with a 10 second record length delivered from each shot location.

Being able to fire as frequently as needed and capture records of lengths as needed does not tell the full story. The physics suggests that increased shot frequency would also result in shallow reflections from subsequent shots being superimposed on deeper reflections from earlier shots. This phenomenon highlights the second crucial component technology of XArray, which is

Figure 2. Shotput record shown in Figure 1 after removal of overlapping shot.

Figure 1. Shot record from the Capreolus 3D survey showing overlapping shot energy starting at 6 seconds (12.5 m SPI).

Table 1. Subsurface line shotput interval and nominal fold

Sail line SPI (m) 10 12.5 18.75 25

Number of sources Subsurface line shotput interval (m)

1 10 12.5 18.75 25

2 20 25 37.5 50

3 30 37.5 56.25 75

5 50 62.5 93.75 125

Number of sources CMP fold achieved with 8 km streamers

1 400 320 213 160

2 200 160 106 80

3 133 106 71 53

5 80 64 42 32

The table shows subsurface line shotput interval and nominal fold for different combinations of sail line shotput and number of sources. Cells highlighted in light green refer to typical configurations found in conventional and XArray acquisition. Dark green and orange cells compare an example XArray triple source configuration, and a conventional dual source configuration respectively.

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the effective removal of interfering shot energy in processing, producing full-length clean records. When combined with continuous recording, field record lengths can be optimised based on shotpoint interval to ensure no ‘recording dead time’ between consecutive records while at the same time minimising the number of duplicate samples between consecutive records.

The Capreolus 3D survey acquired by Polarcus off the west coast of Australia and processed by Downunder Geosolutions is a perfect example of this. The survey covered over 23 000 km2

of an area that had previously been explored over 20 years ago, but was receiving renewed interest after a well drilled in 2014

encountered oil. What was particularly interesting about this oil find is that according to the widely regarded understanding of the petroleum system, the source rock was in the gas window in the vicinity of that well. A full reworking of the petroleum system interpretation was required, which presented a unique seismic problem – acquire with dense shotpoint intervals to maximise effective fold (fold inside the inner mute) and resolve subtle stratigraphic and structural elements of shallow reservoirs, while still capturing long record lengths to ensure illumination of source rock and basement down deep. Conventional, source initiation constrained shooting would require separate surveys

to achieve both of these objectives, one with a short shotpoint interval/record length pair for getting the fine detail in the shallow, and a second with long record length for capturing deep reflections. By using continuous recording in the field to decouple the shotpoint interval form the record length, a 12.5 m shotpoint interval was paired with an 8 second long record, the bottom three seconds of which contained overlapping energy from the subsequent shot. Consecutive 8 second shot records from the field were then concatenated into super records at Downunder Geosolutions’ Perth processing centre, where interfering shot energy was removed, and 12 second clean records output. The dense shotpoint interval satisfied the need for high horizontal and vertical resolution in the shallow section, while the 12 second long record length ensured that reflection energy from the deep targets was captured. It is worth noting that the absence of ‘recording dead time’ in the field means that final clean records could be output at any reasonable user-desired length.

The Capreolus survey proved that the method of dense shotpoint acquisition with continuous recording, paired with overlapping shot removal in processing was effective, robust, and reliable over what is probably one of the largest 3D marine seismic surveys ever acquired. The data density was increased by 150% compared to what would have been achieved with the 31.25 m shotpoint interval that would have been required to produce 12 second clean records in acquisition. The company has since acquired with ~9.5 m shotpoint interval on a recent survey, a further 25% increase in data density. While some may argue that the orders of magnitude increase in data density made possible by this overlapping shotpoint acquisition and processing would have the greatest impact on the final image, leveraging this shot density over multiple Figure 4. XArray triple source geometry.

Figure 3. Conventional dual source geometry.

Table 2. Cross line CMP sampling interval

Streamer separation (m) 62.5 75 100 150 200

Number of sources Cross-line CMP sampling interval (m)

1 31.25 37.5 50 75 100

2 15.63 18.75 25 37.5 50

3 10.42 12.5 16.67 25 33.33

5 6.25 7.5 10 15 20

Number of streamers Sail line interval (m)

8 250 300 400 600 800

10 312.5 375 500 750 1000

12 375 450 600 900 N/A

The table shows cross-line CMP sampling interval, and sail line interval achieved for different number of source/streamer separation pairs, and a number of streamer/streamer separation pairs. Dark green and orange cells compare an example XArray triple source configuration, and a conventional dual source configuration respectively.


sources can still retain the benefits of inline shot density, while reducing the cross-line CMP sampling achieved per unit of streamer separation. This can prove beneficial to the large majority of surveys and is the essence of the XArray offering.

The cross-line CMP sampling interval achievable with a given source and streamer configuration is calculated by dividing the streamer separation by two times the number of sources. Single or dual sources were the only geophysically viable option available for use in narrow azimuth acquisition up until XArray, as shotpoint intervals were limited by the clean record requirement and the reduction of inline fold from increased shotpoint interval from using more sources would not be acceptable. However the increased shot density described in previous paragraphs has made it possible to acquire with three or five sources while keeping the subsurface line shotpoint interval, and CMP inline fold comparable to what is achieved on single and dual source surveys. This has opened up a tremendous opportunity to a) increase survey efficiency while maintaining adequate cross-line CMP sampling and fold, and b) to achieve high-resolution, dense cross-line sampling while maintaining survey efficiency and CMP fold.

To illustrate the efficiency case, consider a scenario where 25 m cross-line bin size is required while maintaining 80 fold over 8000 m long streamers. This could be achieved, as highlighted by orange cells in Tables 1 and 2 below, by deploying a 12 x 100 m x 8000 m spread with dual sources fired at a 25 m (50 m same source) shotpoint interval. The same could be achieved, as highlighted in dark green cells, by deploying a 12 x 150 m x 8000 m spread with three sources fired at a 12.5 m shotpoint interval (37.5 m same source) for example. Twelve streamers at 100 m separation would require a line interval of 600 m however, as opposed to 900 m for the 12 x 150 m spread – a 50% increase in efficiency. This difference in efficiency becomes more pronounced as the width of the streamer spreads increase as shown in Figure 5, an interesting consideration in light of the mega-wide spreads being towed in today’s budget constrained environment.

Admittedly, similar efficiency to that achieved by the triple source, 12 x 100 m x 8000 m solution in the example above is possible with a dual source configuration, but it would either require 50% more streamers in the water to maintain the 25 m crossline bin size (18 x 100 m x 8000 m with dual source) or an increase in crossline bin size to 37.5 m, a considerable reduction in data quality. The benefits derived from having 50% less gear in the water may not be as immediately obvious as those gained from improved sampling density, however the operational and HSE impact on the project is significant. Less gear in the

water means fewer workboat activities and back deck operations for onboard personnel, less risk of cable accidents and fewer batteries and consumables required to maintain a healthy spread.

The XArray methodology has also been implemented on a survey where the target benefitted from the resolution captured by 6.25 m x 6.25 m bin dimensions. This implementation was based on a 62.5 m streamer separation with five sources fired at a 10 m shotpoint interval, resulting in a same source shotpoint interval of 50 m.

Through the use of dense shotpoint intervals, multiple sources, and overlapping shot attenuation in processing, Polarcus has developed a powerful offering for greatly improved cross-line CMP sampling. It offers 6.25 m x 6.25 m bin dimensions for high resolution work, while making the mega-wide spreads being towed today for maximised efficiency geophysically and operationally viable on a wider range of surveys. This comes with benefits of increased fold, and less HSE exposure for offshore crew and equipment. With over 36 000 km2 of XArray and dense shotpoint data acquired in the last 18 months, and with an additional 10 000 km2 planned for the near future, this system has demonstrated its robustness as a geophysical solution, bringing value through solving tough geophysical challenges effectively, efficiently and with reduced HSE risk.

Figure 6. Subsurface coverage versus cross-line sampling for common XArray and dual source configurations.

Figure 5. Increased efficiency of triple source versus dual source using the same cross-line sampling.

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THE EVOLUTION OF HYBRIDS

ALEX WONG, SHEAR BITS, CANADA

HIGHLIGHTS HOW NEW DRILL

BIT TECHNOLOGY IS IMPROVING

WELLBORE ECONOMICS.

A lthough the recent slowdown in global drilling activity and the persistence of reduced oil prices present a tough economic challenge for many oilfield service companies, the present

condition of the drilling industry also paves the way for innovation and new ways to improve wellbore economics. More specifically, in the world of drill bits, there are currently vast opportunities for small, focused development teams to turn their attention toward the progression of new technologies, especially as conventional drill bit designs continue to approach their technical limits in terms of performance and durability.

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The vast majority of wells around the world are still drilled by traditional PDC and rollercone bits, both of which have unique sets of benefits and drawbacks. The shearing mechanism of PDC bits enables increased rate of penetration (ROP) capability and aggressive drilling behaviour, but can often produce undesirable torque response. In terms of durability, some applications still cannot be feasibly drilled by PDC bits, due in part to the limitations of even the industry’s best PDC cutters to resist abrasive, thermal and impact damage in a conventional fixed-cutter layout. Rollercone bits and some hybrid designs continue to excel in certain situations – for instance, when excellent toolface control or high impact resistance is desired – but often lack in ROP potential and are restricted in operating hours by seal and bearing life.

To address the limitations of conventional drill bits, SHEAR BITS introduced Pexus™ Hybrid Drill Bit technology to the industry in mid-2013, and since then, has evolved the technology through a philosophy of continuous improvement. Each run with these bits brings valuable new information to the development team, which communicates closely with operators to find opportunities to increase performance and expand the technology into a wider range of applications. In a few short years, these bits have performed hundreds of runs, totalling over 1 million ft drilled.

Advantages of the technology Pexus Hybrid Bits employ a layout comprising a set of primary, leading gouging inserts, and a secondary PDC shearing cutting

structure1 (Figure 1). The gouging elements are offered as either rotating or fixed components in either carbide or diamond, and other custom configurations are available to suit a wide variety of applications. This hybrid cutting structure provides performance advantages in three key ways: Ì Uses two cutting structures to fail the formation, with the

gouging elements in a leading position to fracture the rock initially. Consequently, the individual loading on each trailing PDC cutter is lessened, enabling them to maintain ROP and stay sharper in longer runs.

Ì Gouging inserts in a leading position protect the secondary PDC cutting structure by dislodging clasts from the formation such as large debris (gravel and boulders), or coarse grained conglomerates (large pyrite and chert fragments). These particles can be carried away through fluid pathways before they are able to damage the PDC cutters.

Ì Fine adjustment of the relative position between the gouging and shearing elements enables the bit to control the amount that each cutting structure interacts with the formation. This has repeatedly proven to provide a far smoother torque response and greater directional control over conventional PDC bits.

Stages of evolutionTo date, the technology has undergone three major ‘generations’ of development, each of which targeted a different range of applications where conventional drill bit designs fell short. Efforts are underway to both improve on current designs and bring completely new ideas to the table.

Figure 1. Pexus hybrid gouging/shearing cutting mechanism using either rotating (left) or fixed (right) inserts.

Figure 2. Generation 1 (left), Generation 2 (centre), and Generation 3 (right) Pexus hybrid designs.

First generationGeneration 1 Pexus designs were born out of a need for a more effective drilling solution in formation types where PDC bits were easily and quickly damaged – this includes gravel, boulders, chert, and pyrite, which are normally drilled by rollercone bits at relatively low ROPs. Test runs in these rock types have also been performed in the past using mining bits, but were met with limited success (mining bits contain gouging inserts as the only cutting structure). Although these


test runs occasionally showed promising ROP potential, they typically became damaged beyond repair in intervals as short as 500 ft. Such a lack of durability can be attributed to the inability of gouging inserts alone to withstand harder and more consolidated formations.

The Generation 1 design (Figure 2) features densely spaced gouging inserts positioned well above the PDC cutting structure – this results in very smooth drilling behaviour and excellent durability. Even the first prototype bit produced positive field results on its initial runs, thereby proving the inherent performance advantages of the hybrid technology. However, due to the excellent condition of the majority of the dulls, the development team concluded that more ROP could be gained by making a few key design changes.

Second generationThe Generation 2 design (Figure 2) features more widely spaced gouging inserts positioned closer to the PDC cutting structure. This enables the PDC cutters to engage more actively in the formation, to significantly boost ROP while retaining the durability and control benefits of the hybrid technology. Wider insert spacing also allows for increased face volume and flexibility in hydraulic layouts, enabling the bits to clean and cool both cutting structures effectively at higher ROP.

One of the most consistently successful applications for Generation 2 designs is in Western Canada, drilling 2000 ft surface intervals in a single run that would otherwise require at least one rollercone and one PDC bit. Operators in these applications save many hours by eliminating a trip while even occasionally matching the ROP of a PDC bit. The excellent steerability of these designs has also been demonstrated by numerous other runs on directional assemblies in bit sizes ranging from 6 ¼ in. to

24 in., many of which replaced rollercone bits and successfully met demanding directional requirements.2

Third generationThe company identified even more opportunity for Pexus technology by directly targeting the conventional PDC market. Generation 3 designs (Figure 2) were developed to match or exceed the ROP capability of PDC bits in these applications, while using the Pexus cutting structure to improve torque response and protect the PDC cutters from damage. They generally contain fewer blades than conventional PDC bits – for example, in one 12 ¼ in. diameter Western Canadian application that typically uses 616 (six blades, 16 mm cutters) or 519 type PDC bits, more aggressive 419 type Pexus designs have achieved continued success in terms of both ROP and durability.3

Generation 3 designs also feature a significant change in hydraulic layout that aims to improve cooling in thermally demanding environments, and provide superior cleaning in high ROP applications. Computational fluid dynamics (CFD) analyses were performed to illustrate the positive effects of having dedicated flow paths directly in front of each cutting

Figure 3. CFD comparison between Generation 2 (left) and 3 (right) Pexus hybrid designs.

Figure 4. From left to right: a 12 ¼ in. hybrid bit, a 8 ¾ in. hybrid bit, and a 6 ¼ in. hybrid directional bit.


structure (Figure 3). Additionally, to meet the demands of more main hole applications (typically below 8 ¾ in. diameter), many of these designs are built using non-rotating diamond gouging inserts that maximise wear resistance in long and challenging intervals.

Case studiesAn operator in Western Canada was attempting to drill an 8 ¾ in. diameter interval, reaming a 95 ft long section in a predominantly hard limestone formation of roughly 20 ksi compressive strength, followed by a 185 ft interval in a predominantly dolomite formation of comparable strength. Although short, this interval is very challenging mainly due to the lithology of both formations – reaming is difficult with conventional PDC bits, which frequently produce erratic torque response, poor hole condition and excessive damage on the gauge area of the bit in similar wells. Instead, 547 or 617 type carbide insert rollercone bits are generally used, but usually only ream at a 6 - 10 ft/hr average ROP and are subsequently tripped out for a PDC bit in the lower section. Using a Generation 3 Pexus hybrid design (Figure 4) enabled the operator to ream at approximately twice the ROP of a typical rollercone, saving over 10 hours of operating time, as well as eliminating a trip by drilling the entire section in a single run.

The dull condition (Figure 5) showed minimal component damage in the cone and nose of the bit, largely due to the added protection provided by the hybrid cutting structure. The reaming portion of the run caused moderate to heavy breakage of the

gouging inserts and some PDC cutters on the outer shoulder and gage; thus, it was concluded that future designs for main hole applications could benefit from additional diamond volume and protection in these areas.

Using the lessons learned from the 8 ¾ in. run, a Generation 3 Pexus design (Figure 4) was provided for a different operator in Western Canada, drilling a 6 ¼ in. diameter, 1330 ft long build interval through two formation types both consisting primarily of siltstones with interbedded shales. In order maximise durability in an application with high impact, abrasion and thermal demands, the design featured twice as many blades of PDC cutters on the outer shoulder and gauge compared to the 8 ¾ in. bit.

The operator commented that the bit provided very consistent toolface control, even when run with extremely high weight on bit (up to 40 000 lb) while sliding and when transitioning from one formation type into the next. As evidenced by the dull condition (Figure 5), the additional blades of PDC cutters provided the outer shoulder durability necessary to complete the interval with only minimal wear on the PDC cutters and occasional chipping on the gouging inserts.

Generation 3 Pexus designs have also completed over 25 runs in surface applications since late 2015. In one field area in Western Canada, 12 ¼ in. hybrid bits are routinely outperforming PDC bits in a formation of 4 - 10 ksi compressive strength containing sand, shale, and some coarse grained sediments. A search of 11 close offset wells shows that 419 type Pexus hybrid bits achieved an average ROP increase of 69% over 616 type PDC bits in run lengths between 1820 and 2020 ft

(Figure 6). The reduced blade count consistently provides the added aggressiveness needed to significantly boost ROP, without sacrificing toughness or steerability.

ConclusionSince the initial design concept, Pexus hybrid drill bit technology has taken significant strides in its development. Three generations of design iterations have continuously strived for improvement, consistently achieving positive results over hundreds of runs in a wide variety of applications. The hybrid gouging/shearing cutting structure is engineered to provide superior rock fracturing capability, protection, and directional control over conventional drill bit designs.

References1. Beaton, T., ‘A Hybrid Solution’, Oilfield

Technology, (November, 2014), pp. 45 - 49.

2. Beaton, T., ‘Getting Ahead with Hybrids’, Oilfield Technology, (June, 2015), pp. 51 - 54.

3. Cookson, C., ‘New Drill Bits Boost Efficiency, Safety’, The American Oil & Gas Reporter, (April, 2016), pp. 80 - 87.Figure 6. Average ROP comparison of 11 close offset 12 ¼ in. diameter intervals.

Figure 5. Dull condition of a 8 ¾ in. Pexus hybrid bit after completing a challenging reaming and vertical section (left). Dull condition of a 6 ¼ in. Pexus hybrid directional bit after completing a challenging build section (right).

MASTER YOUR TERRAIN

With the development of diamond-leached cutter technology and other material advancements, the industry made significant improvements in PDC bit

durability over the last few decades. Stability and steerability improvements were another significant focus, and great strides have been made in the last 30 years.

But little consideration had been given to drill bit efficiency – to maximise rates of penetration while using the least amount of energy This became the concept and philosophy for the ReedHycalog™ Tektonic™ drill bit platform.

First, the researchers and engineers at NOV examined every aspect of the drilling process: how to initiate rock failure as efficiently as possible; ways to minimise the frictional losses associated with cuttings movement up the cutter face and along the blade; means to efficiently distribute cutter loads on the bit body; and methods to ensure cuttings are evacuated from the face of the bit as quickly and efficiently as possible.

Thousands of hours were spent to develop, simulate, test and validate new designs and bit features aimed at maximising drilling efficiency and rates of penetration, which were combined with proven attributes for durability, stability, and steerability.

In order to specifically tailor bits for myriad challenges and environments around the globe, regional bit design engineers were provided with a design toolbox so they could use a combination of features to build the best bit for any given application.

New analysis software was developed, as well. Dynamic rotation bit modelling software is used to examine cutter forces under non-concentric bit motion conditions that more accurately match what is encountered downhole and to optimise each bit’s cutter loading, transient bit-rock interactions, and wear characteristics. Advanced fluid flow modelling software uses techniques to quantify and improve hydraulic cleaning and cooling performance. Examining the interaction between cuttings and drilling fluid helps the regional design engineers maximise hydraulic energy in critical areas, ensuring quick and efficient evacuation and providing high-velocity fluid to the cutters to prevent thermal degradation.

Research for the Tektonic platform also resulted in the development of the new Reflektor™ mirror-finish cutters, which offer improved wear and impact resistance. New cutter geometry, surface finish, and edge treatments improve cutting efficiency. Lab tests in sandstone and shale using a pressure chamber to simulate downhole conditions showed increases in ROP – 85% in shale and

MASTER YOUR TERRAIN

ALEXIS GARCIA, BRAD IVIE AND ANDREW MILLER, NOV, USA, INTRODUCE A NEW GENERATION OF PDC BITS.

COVER STORY

| 25


nearly 150% in sandstone – while requiring less mechanical specific energy (MSE) than previous generations of PDC cutters.

With the launch of the product at the end of last year, the results in the lab were validated with performance in the field.

Case studies

North DakotaAn operator in the Bakken Shale, North Dakota, USA, had an objective to drill the 5 ⅞ in. lateral section with a single BHA while maintaining high ROP. Regional design engineers suggested a five-bladed 5 ⅞ in. Tektonic bit with 16 mm Reflektor mirror-finish cutters would be best suited for the formation. The bit, matched with an Agitator™ system and an ERT™ power section that was tailored for the Bakken, drilled the lateral section with an average ROP of 143 ft/hr – a 34% increase over the offset average and an operator record for a lateral section. The bit completed the 9293 ft interval in a single run, too, besting the offset interval average by 62%.

TexasIn the Eagle Ford Shale, Texas, USA, an operator wanted to drill the 12 ¼ in. surface interval in a single run with high ROP while maintaining a good dull condition. The regional design engineer

offered a six-bladed 12 ¼ in. Tektonic bit with Reflektor cutters that were well suited for high impact damage applications for use on an 8 in. 7:8 lobe 4.0 stage drilling motor with a 1.5˚ fixed-bend. The bit drilled from 125 ft to 3980 ft in six hours, averaging an ROP of 642.5 ft/hr. This was 59% faster than the best competitor offset ROP and an operator record in the region. The bit was pulled with an impressive dull condition of 0-0-NO-A-X-I-NO-TD.

AngolaIn the Malongo West field in Angola, a directional driller had an objective to drop inclination from 13.24˚ to 0˚

and vertically drill to TD with competitive ROP in the 12 ¼ in. section. For use on a rotary steerable system, the regional design engineer provided a six-bladed 12 ¼ in. bit with 16 mm cutters. Though lithology predominately consisting of halite with a few anhydrite stringers, the bit drilled the entire 1931 ft section to TD in a single run. With an ROP of 77.2 ft/hr, the bit provided 58% greater ROP compared to offset averages and set a new field record.

OmanTektonic bits have also been proven in the Middle East. In the 12 ¼ in. vertical section in a well in Oman, an operator had an objective to drill to TD with competitive ROP using a drilling motor. The regional design engineer recommended a five-bladed 12 ¼ in. bit with 19 mm cutters to get the best performance through the carbonate and shale formation. After drilling the entire 2484 ft vertical section with an ROP of 138 ft/hr, the bit was pulled out of the hole in excellent condition (0-0-NO-A-X-I-NO-TD). This run was a new field record, with 4% greater ROP and a 14% longer interval than the best offset.

Also in Oman, a customer wanted to drill the 12 ¼ in. vertical section in a single run at a high ROP using a rotary assembly. For a formation consisting of limestone, dolomite, shale and highly abrasive sandstone sequences, the regional design engineer provided a six-bladed 12 ¼ in. bit with 16 mm cutters along with a ReedHycalog NV near-bit stabiliser. The bit delivered a record-setting performance, drilling the entire section and outperforming the matrix bits that were the standard choice for the section. In just over 169 hours, the bit drilled 8553 ft and set a field record for ROP at 50.5 ft/hr – a 23% improvement over the field average ROP.

Another six-bladed 12 ¼ in. bit with 16 mm cutters was recommended for an operator to drill a sequence of shales and carbonates, with the hardness of the carbonates increasing with the depth. The bit drilled the entire 8136 ft vertical section in a single run with an average ROP of 75.4 ft/hr, providing a 71.4% increase over the median offset ROP and setting a new field record. The bit exceeded all customer expectations, and on the surface it was graded 3-4-WT-A-X-I-BT-TD.

ChinaIn North Xinjiang Province, China, an operator wanted to drill an 8 ½ in. vertical section on a water-based mud system at a competitive ROP to reduce drilling days, improve drilling efficiency, and save overall costs. Based on thorough offset analysis, the regional design engineer recommended a specially designed five-bladed 8 ½ in. bit with 19 mm cutters. In its first run, the bit set a new ROP record for the area, drilling 2070 ft through claystone, sandstone, and conglomerate formations with traces of tuff and andesite. With an ROP of 34.32 ft/hr, the run was 108% faster than average and 50% faster than the best offset. Using a Tektonic bit saved the operator a total of five days and approximately ¥200 000, and the dull condition was such that the bit was rerun on another well, offering further savings.

SummaryNew records for performance and drilling efficiency are being set as the Tektonic drill bit platform expands around the globe. New combinations of features and elements for Tektonic bits are helping to increase performance in other challenges, including deepwater and hard rock applications. And as the industry demands greater performance and efficiency in its operations, drill bits with designs tailored for the application and environment are an essential part of the equation.

Figure 1. The Tektonic bit platform is designed for efficiency, speed and reliability.

Figure 2. Tailored features, such as cutters and flow guides, optimise each bit for the application.

REFINING BITS FOR RSSARON DEEN, MATT CASE AND JOSH CRISWELL, ULTERRA, HIGHLIGHT HOW CUSTOMISED BIT DEVELOPMENT FOR RSS REDUCES TOOL FAILURE.

I t is understood that all new technologies struggle in their infancy to gain adoption due to numerous economic and technical

reasons. Among these are high cost, problematic reliability, lack of understanding, and marginal value proposition. Over years of learning, development and refinement these hurdles are overcome, and with each step new opportunities open up. No technology has followed this path more closely than rotary steerable systems (RSS), which is finding new value in this historic downturn.

Another facet of technology adoption is the availability of compliments. For example,

smartphones need great apps for customers to realise their true value. In much the same way, RSS need to have quality drill bits that are designed to work with them in order for operators to realise their maximum value.

To be sure, there are certainly some obstacles to working across company lines on product development. For example, one of the many aspects of customising bit designs to work perfectly with differing RSS tools is nuanced gauge pad configurations. Different lengths, steps, tapers, helix angles, and wear protection may be advantageous for one RSS application, but producing such a specific product requires

| 27


a significant investment of engineering resources and capital. And once created, such a bespoke asset should not be blindly force fit into an improper application to the detriment of

another operator. The only long-term path over such hurdles for service companies is to jointly commit to focus first on performance for the customer.

Reducing vibrations, reducing tool failuresReducing vibration is particularly important in wells that utilise RSS, which are becoming more popular as well planners are pushing the limits on directional difficulty and lateral lengths. Most RSS tools are highly susceptible to failure due to vibration, which is one of the most common reasons the BHA must be tripped. RSS directional hands will often monitor these vibrations and are forced to reduce drilling parameters, and sometimes stop drilling altogether to pick up off bottom when vibrations get too high. Vibrations in a way act as an ROP ceiling, limiting the driller to lower parameters than what is necessary for maximum ROP.

Ulterra’s CounterForce® technology uses the cutting structure to reduce vibrations at the bit, which increases efficiency and reduces bit damage. With the ability of the cutting structure to reduce vibrations, operators can not only reduce the number of trips for tool failures, but can also effectively elevate the ROP ceiling so that they can drill faster and still avoid high vibrations.

The claim that CounterForce can reduce vibrations, and therefore increase ROP and reduce the number of trips has been validated through numerous field runs. A major operator in South Texas utilises the Weatherford Revolution RSS to drill out from under surface through the curve and lateral to TD in one trip. Comparing the U516M verses alternative bits in this application in the years 2014 and 2015, the U516M on average drilled 7% faster. More importantly, RSS runs with standard PDC bits of any manufacturer were nearly three times as likely to be pulled for tool failure (Figure 3). The U516M completed 39 runs within this time frame.

The technology’s performance has also been validated through electronic drilling recorder (EDR) analysis. A four well pad in South Texas, again utilising the Weatherford Revolution RSS, ran the U516M on three wells, and a competitor bit on the fourth. The stick-slip magnitude, measured in a rotational value of c/min, was 35% lower for the average of the three CounterForce runs compared to the offset. In addition, the average ROP for the three CounterForce runs was 27% faster than the offset, saving the operator 13 hours on each well the U516M was in the hole.

Figure 1. Traditional PDC cutting structures are laid out to be balanced, or neutral to drilling vibrations.

Figure 2. The cutting structures are engineered to take an active role in damping harmful drilling vibrations.

Figure 3. The percentage of RSS runs pulled for downhole tool failure. Rotary Steerable tool reliability has positively correlated with the use of CounterForce bit technology over a statistically significant data set.

The technology has also been tested in demanding applications offshore in the Gulf of Mexico. A major operator drilling in the Eastern GoM utilised the 16.50 in. U713M bit to drill a 2600 ft. section through the Base Miocene and Cretaceous formations. This operator was particularly concerned with high vibrations through these formations due to offsets they had drilled in the past. The U713M bit was able to decrease stick-slip vibration by 26% and increase ROP by 12% compared to said offsets.

Going past ‘OEM’In the past several months, operators drilling in the Wolfbone area of the Delaware Basin have been looking more to RSS to reduce the time spent drilling horizontal wells. RSS have become a more affordable option due to their reduced cost in the down market, but improved performance is still required to complete the value proposition.

Upon introduction of the RSS into the application, the RSS manufacturer recommended their own PDC drill bits to be used with the system. Parameters and bit selection were varied over several runs, as were results, with runs being terminated too often and too soon. After multiple attempts to complete the interval in one run without success, some operators chose to seek out other alternatives to push for efficiency gains through competition. Ulterra was challenged to create a bit design that was capable of finishing extended laterals in one run while encountering shale with varying carbonate content. The criteria for success in this application is extremely efficient, high rates of penetration, produce accurate corrections on a motorised push-the-bit system, and withstand the higher RPM capabilities of new rotary steerable systems.

To respond to these requirements, engineers designed an 8.5 in. U616S with CounterForce technology. The U616S also features an extended gauge pad designed to best utilise the features of the specific RSS in use, in this case Schlumberger’s PowerDrive Orbit™, to help the bit track in long laterals and reduce corrective actions. This new design also increases the junk slot area by nearly 12% from previous iterations to expedite the removal of cuttings from the cutter faces, allowing higher ROP.

In two consecutive trials, the new 8.5 in. U616S bit completed both intervals successfully in one run, producing an average ROP 15% higher than the RSS manufacturer’s own recommended designs. The ability to complete the interval in one run while producing higher ROP reduced operator drilling costs by an average of US$7.24/ft, or a total of over US$67 000 in the lateral section.

ConclusionAcross all industries, most companies usually focus their energy and expertise on their tools and services and leave complimentary performance parts to other experts. This is true for RSS makers like Weatherford, Gyrodata, Scout Downhole, and others. Some companies, however, produce their own OEM (original equipment manufacturer) drill bits, and obviously they will often recommend them with self-benefiting reasons.

In high-cost, high-performance applications, which are often identifiable by the use of RSS, ‘stock’ equipment is seldom the best option. There are many great car makers, but they all rely on other companies for the best tires in the world. Similarly, independent of the make and model of RSS tools, the evidence is growing that pairing them with a vibration reducing, performance enhancing bit is a good decision.

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Record footage increases in hard, abrasive formations are being achieved across a variety of bit sizes and configurations with an application specific

diamond-impregnated (DI) bit. The design enables fit-for-purpose optimisation and fast-paced refinement to achieve significant performance improvements in durability and ROP. In recent applications in Canada and Oman, the design has set new standards for footage drilled and drill out capabilities.

The Varel Fusion® bit is a matrix body design with diamond-impregnated segments on each blade and thermo/abrasion resistant PDC cutters in the bit centre. The optimised segment geometry maximises bit durability without impacting efficiency. Benefits are achieved through several advances, including diamond pelletisation, high density segments, a low heat infiltration process, and a cutting structure design programme that allows placement of individual segments in the bit face to be customised for the application needs.

Customising the bit A key aspect of Fusion design concept is ensuring the diamond grit mix is the correct one for the bit’s specific application. Grit mix refers to the actual diamond size and/or mixture of diamond sizes that are used. The best performance is typically achieved when grit is optimised over subsequent runs for the specific target formation. This is a very significant factor in the ROP but also impacts diamond volume, wear characteristics, durability, and the bit’s ability to drill through varied lithologies such as carbonates and/or changing shale content.

One of the main advantages of the Varel design is its ability to be quickly modified based on the dull bit characteristics. Hot isostatic pressing (HIP) inserts can be moved, made bigger, and adjusted to maximise diamond volume at a particular radius if so required (Figure 1).

BRUNO CUILLIER, AURELIEN MANGENY,

BRAD TAKENAKA & DANNY TILLEMAN,

VAREL OIL & GAS DRILL BITS,

EVALUATE THE PERFORMANCE OF

APPLICATION-SPECIFIC DIAMOND

IMPREGNATED BIT DESIGNS IN

CHALLENGING DRILLING CONDITIONS.

WITH DIAMONDS

| 31


For example, experience in Canada determined that increasing the blade height increased durability. Not only did this increase the diamond volume of the blade, but it also allowed more geometric space ‘inside’ the blade to work with. HIP inserts were made bigger, which was advantageous as they have superior diamond dispersion characteristics.

A second development for the bits used in Canada were the design changes to reduce the likelihood of the bit getting stuck. The overall length of the bit was reduced to decrease the bit-to-bend length, the passive portion of the gauge was

undercut, and back ream cutters were added. The enhanced performance was not achieved on the first bit run, but instead was the result of ongoing design modifications all based on the concept of custom designing the bit for a specific formation.

Canadian run performanceFusion bits have been used in many Canadian wells with a significant improvement in performance versus competitor bits used in offset wells.

In the Lily Field in British Columbia, Canada, the Fusion bit drilled faster and for a longer time than any other bit used on the well pad, requiring only one bit to drill the section. Drilling the 8 ½ in. vertical and build section typically requires two DI bits to drill the full interval at an average of 2.5 m/hr (8.2 ft/hr). By drilling 204 m (669 ft) at 3 m/h (9.8 ft/h), the Fusion DI bit improved the average ROP by 20% and eliminated the cost of another trip and a second bit.

The record setting performance is mirrored in other Canadian applications that have also seen improved durability and ROP using the application specific bit design.

In the Graham Field, the first run of a Varel VF1213 171 mm (6 ¾) DI bit drilled above average footage at the fastest ROP compared to offset DI runs drilled by two different competitor bits in four separate runs. The Varel design made 84 m in 29.75 hours at 2.82 m/h compared to the offset average of 78.25 m drilled in 39.46 hours at 2.03 m/h. The Varel F1213 drilled 29% faster than the competitor average.

The Graham Field illustrates the type of formations where the DI bits are used. Typically tripped in at the bottom end of the Charlie lake formation and pulled just before the Montney, the bits encounter an unconfined compressive strength (UCCS) of 30 to 45 kPSI through this section. The lithology is primarily abrasive sand, limestone and silt, making this an ideal candidate for DI bits as PDCs dull off rapidly and roller cone bits are very slow (< 1m/hr).

In the Town Field, a 216 mm F1616G2U Fusion bit drilled 194 m in 55.25 hours at 3.51 m/h compared to the offset average of three offset bits of 153.6 m in 46.25 hours at 3.33 m/h (Figure 1).

An Altares Field application used a 171 mm F1213 Fusion bit to drill 217 m in 77 hours at 2.82 m/hr, 93% further than the average meterage (112 m) in the area. All runs utilised a high-speed motor. The formation compressive strength in this section can reach as high as 45 kPSI with extremely abrasive sand making conventional drilling uneconomical. To give an example of how challenging this section is to drill, a six blade 13 mm PDC bit was tested. It drilled 7 m at 3.11 m/hr before being pulled for penetration rate. The Varel F1213 allowed the customer to stay on bottom longer while achieving an exceptional rate of penetration.

Oman run performanceIn Oman’s West Khulud Field, an F1613G Fusion bit now holds the top three records for an 8 ⅜ in. single-run diamond-impregnated bit. The most recent run increased footage by 46% over the second run and a 223% gain in average offset footage using other bits (Figure 2).

The Fusion bit runs in one of the deepest gas fields in the world were initiated to exit the casing shoe and drill as deep as possible in a single run. The field’s lithology presents a significant challenge with abrasive sand, shale, and silt exhibiting unconfined compressive strengths in the range of

Figure 1. Varel modifies HIP segment size, shape, and placement to ensure the best design possible for any application.

Figure 2. Varel’s 216 mm F1616G2U drilled 26% farther than the average offset in Town Field, British Columbia.

Figure 3. The F1613G used in this West Khulud Field run saved the operator two trips, two bit changes, and eight days from the planned schedule.

Impreg Impreg Impreg F1616G2U Average

216 mm Impreg Runs - Town Field, British Columbia

1650

1700

1750

1800

A mrk

Artex

Halfway

Doig

Montney

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2050 3.0

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3.15

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3.25

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3.35

3.4

3.45

3.5

3.55

Drilled Interval

ROP

Mea

sure

d D

epth

(m

)

RO

P (

m/h

r)

F1613G F1613G F1613G Impregs ImpregsImpregs

2.15 m/hr 1.97 m/hr 2.1 m/hr 2.07 m/hr 1.34 m/hr1.42 m/hr

8-3/8” Impreg Runs - West Khulud Field, Oman Drilled Interval

Wel

l Dep

th (

m)

4000

4200

4400

4600

4800

5000

5200

SOLUTIONS TO TODAY’S CHALLENGESENSURING TOMORROW’S SUCCESSToday’s oil and gas market presents unique and dynamic challenges. At Cudd Energy Services (CES), we are committed to delivering integrated solutions with the long-term health of your investment in mind. We focus on providing solutions that improve effi ciency, increase productivity and reduce costs for the lifecycle of your investment. With a team of experienced, industry-certifi ed engineers and specialists at the helm of each project, you receive unparalleled expertise to help you achieve your operational objectives safely and effi ciently.

For more information about our complete portfolio of services, visit www.cudd.com today.

STIMULATION │ COILED TUBING & E-COIL │ COIL DRILLING TECHNOLOGIESHYDRAULIC WORKOVER │ CEMENTING │ INDUSTRIAL NITROGEN │ NITROGEN

SLICKLINE & BRAIDED LINE │ ELECTRIC LINE │ WATER MANAGEMENT SPECIAL SERVICES │ WELL CONTROL


20 to 55 kPSI. As a result, bit life and ROP have been greatly limited, with multiple trips from 4000 m and deeper. Typically, three to five bits are needed to drill the section.

The latest record run bit drilled 859 m (2818 ft) at 2.15 m/hr (7 ft/hr). The performance saved the operator eight days from the planned schedule, including the elimination of two trips and two bit changes.

In addition to the 8 ⅜ in. runs, a 5 ⅞ in. F1213G Fusion bit turned in similar record performance in the Salakh Field. The bit drilled a total of 440 m (1442 ft) at an average ROP of 1.18 m/h (3.86 ft/h), to eliminate trip time and costs for three to four conventional bits.

Bit technologyDI bits are a common tool for improving drilling performance in hard, abrasive formations. Their use has increased with greater understanding of DI bit performance and wear, but performance can still be inconsistent based on variations in rock properties, such as mineralogy, bit segment properties including matrix hardness, wear status, concentration and diamond size.

Field results and dull analysis have shown that a complex wear process is a key factor contributing to DI bit performance. This wear results in the continuous evolution of the cutting face and the exposure of new diamonds. In the process, the depth of the cut results in different wear mechanisms – shallow cuts produce diamond polishing while deeper cuts produce diamond fracturing, diamond losses, and matrix abrasion. Impregnated bits have historically been dedicated designs built to address both hard and abrasive formations.

A primary driver in the recent DI bit advances is computer modelling that builds on advances in materials and manufacturing to target specific formation characteristics. The resulting designs have shown significant improvements in performance over conventional DI bits built to a broader design standard.

The design advance developed by Varel recognises the strong relationship between the volume of diamond available to drill and bit durability. This relationship is determined by

the volume of rock removed versus the volume of diamond losses. Manipulating the material changes this ratio to enable fine-tuning of drilling efficiency. Adjustments are made based on a material performance evaluation after bit use. This quantitative analysis is focused on whole stones, crushed stones, and pulled stones in the cutting structure to determine a balance between matrix hardness, diamond size, concentration, and distribution.

To balance durability and ROP efficiency for a specific application, Varel reviews the design and material selection to address a broad scope of considerations including diamond distribution, sintered segment shapes and composition, hydraulics, diamond grades, and thermo mechanical and chemical damage.

Diamond distribution is crucial to bit performance. It is important to avoid diamond aggregate that can result in partial coverage with areas of low diamond concentration. Pelletising the diamond results in even diamond distribution, provides protection during heat cycles, and improves diamond matrix bonding.

Sintered segments are manufactured using a HIP process to produce customised shapes that accommodate design geometry and optimise diamond volume in a given area. HIP diamond size, concentration, and matrix hardness can also be fine-tuned based on their profile location (inner cone, nose, or outer cone).

Varel’s SPOT-DN™ bit design programme is used to address specific durability and penetration rate targets for the formation. The design process considers diamond volume distribution over the profile (blade material + insert shapes) and material characteristics such as matrix hardness, diamond size, and diamond concentration.

Cutting structure considerations include segment shape. Using individual segments of various shapes allows optimisation of the diamond distribution all along the bit profile. For example, using a drop shape segment allows greater segment height, which yields better area durability because the height of the blade has more HIP segment material in the critical area of the nose taper.

In the case of the Oman applications cited in this article, the shape and geometry of the HIP segment was fine-tuned to achieve better coverage on the nose and shoulder of the bit and increase the ratio of sintered diamond (HIP segment) against a handpack-impregnated matrix. Carat distribution was monitored to avoid weak spots that could result in an early ring out wear progression.

The bit design process also considers how cooling and cleaning are affected allowing necessary changes to optimise fluid distribution and minimise cutting traps.

In addition to design parameters, material selection can be also tailored for the application. As with all diamond-based material, design efforts can be compromised by diamond degradation. The primary challenge is temperature, which causes both mechanical and chemical degradation. This is addressed through a specific low temperature manufacturing process.

ConclusionOptimising the performance of DI bits in a fast, precise process is yielding significant improvements in drilling hard and/or abrasive formations. Using specialised technologies to enhance durability and ROP performance, the application-specific Fusion DI bits are achieving new levels of field performance that strongly validate the customised design.

Figure 4. Fusion DI bits designed for the application outperformed offsets.

KEEP

ING

IT C

ENTR

ALKE

EPIN

G IT

CEN

TRAL IAIN LEVIE,

ANTELOPE OIL TOOLS,

USA, INTRODUCES A

COST-EFFECTIVE SOLUTION

FOR USE IN DEEPWATER

DRILLING.

While many in the oil and gas industry are facing strong challenges to

navigate through challenging times, Antelope Oil Tools is utilising this volatile time to research, develop and innovate new technologies that will optimise well construction efforts, specifically in casing running and cementing applications.

Companies that are actively drilling wells must make their operations as efficient and cost-effective as possible in 2016 and beyond to adjust to today’s market, and the near term forecasts for the industry. Antelope is dedicating significant resources to develop more efficient and cost-effective solutions that are designed to provide an economic benefit without sacrificing performance and reliability.

One of the major challenges associated with drilling deepwater offshore wells is that annular clearances are extremely tight, making the challenge of obtaining maximum stand-off capacity when centralising casing in deepwater well formations increasingly difficult. The most common approach has been to utilise centraliser subs in tight tolerance well applications. However, the company’s ‘On-The-Pipe-Solutions’ offer operators another alternative in many cases for centralising casing strings by installing its CentraMax® Close Tolerance (CT) Centraliser(s) and WearSox® thermal spray directly onto the casing

| 35


joints, eliminating the additional cost of an integral sub body threaded onto the end of a casing joint, which adds length to the pipe and risks additional potential leak paths within the casing string.

Traditional centraliser subs are costly due to the premium threading requirements (to match the casing connection) and body material that is required to meet or exceed the burst, collapse and tensile strength requirements of the casing design.

Alternatively, ‘On-The-Pipe-Solutions’ eliminate these costs by more than 60% in many cases with their direct on-the-pipe installation method. The (CT) centralisers cost per unit is substantially lower than a standard centraliser sub due to the reduced material needed to manufacture the centraliser, lead time and maintenance required. The design reduces lead-time by weeks, if not months, in certain applications. With shorter lead-times, cash flow is greatly improved because the operator has the ability to manage expenditure commitments closer to when the product is required. The CT Series also diminishes the maintenance expense to installed and racked centralisers by offering protective coatings. Antelope’s onto-the-casing direct installation method manages casing string changes and negates requirements to manage and warehouse supplementary inventory. Unlike the CT Series, subs require the operator to hold an inventory longer than necessary, raising the risk of the product becoming obsolete and resulting in additional costs.

Manufactured from a single-piece of 100% heat-treated steel, CT centralisers have a restoring force, ideal for all well conditions. The CT Series includes the RT1, PI1 and PT1 models that offer different anchoring geometrics and allow the operator to choose the design that provides optimum centralisation in any given well. The different designs allow for the casing string to be pushed in, rotated in or pulled in through the wellbore.

Green Canyon Field

The challenge:While drilling on a deepwater project in the Green Canyon Field, Whistler Energy, LLC required a centralisation package for their 3834 ft length of 5.5 in. production liner. The company wanted to run the production liner to a depth of 11 034 ft. The liner was required to pass through a 6.5 in. restriction by previous casing, into a 7.5 in. under-reamed open hole section.

The application required a centralisation product with attributes for providing low starting and running forces for smooth passage through the restriction, and high restoring forces to centralise the liner inside the under-reamed hole. It was also desired that the centraliser would allow for both reciprocation and rotation. Lastly, a solution with a short lead time was required.

The solution:To meet the challenge, the CentraMax PI1 Centraliser and WearSox external stop collars were recommended. The CentraMax PI1 is a one piece centraliser that is designed to be pushed when installed between two external anchoring devices, and is used when radial annular clearance between casing OD and restriction ID are sufficient. For this specific project, the technology was the best on-the-pipe-solution.

The result: Using this centraliser and stop collar, the customer was able to get the casing straight to bottom with no problems resulting in a successful cement job.

Gulf of Mexico

The challenge:An operator drilling in the Gulf of Mexico was faced with a difficult casing string application that required it to run a very deep/heavy weight 16 in. liner to a record depth, in a deviated and under-reamed well bore. Rather than utilise centraliser subs (a more standard offering), the company opted to run Antelope’s on-the-pipe-solution as an alternative.

Well parameters:In the Walker Ridge Field, drilling in 7000 ft of water, the operator was required to run the 16 in. casing through an 18.25 in. ID restriction at the 18 in. supplemental hanger and through an 18.125 in. ID restriction at the 22 in. casing shoe track. The 16 in. liner was to be run to 24 000 ft and centralised in a 21 in. under-reamed hole with 22˚ of inclination. The liner was a mixed string of 16 ft 97# and 16.15 in. 127# casing and weighed more than 2 million lb. The weight was such that the operator would not have been able to POOH after the shoe reached 19 000 ft, making the centralisation even more critical.

The solution:Antelope’s team recommended using the RT1 single piece centraliser with WearSox internal thermal spray metal stops. The RT1 provides clients an improved alternative to in-line centraliser subs. It is pulled in both directions when used with WearSox internal stops. Because of its one-piece design, the RT1 represents improved mechanical integrity, high yield and tensile strengths and eliminates the potential of failure of welds, a critical differentiator when considering the weight of the casing string.

The result:Using the RT1 with a WearSox internal stop, the customer was able to run the casing to the bottom and accomplish their objective of a successful primary cement job. In addition, the client also realised a savings of greater than 60% by installing centralisers directly to the casing, as opposed to using in-line centraliser subs.

Conclusion In nearly all instances, CentraMax ‘On-The-Pipe-Solutions’ proved themselves as a suitable alternative solution to centraliser subs when annular clearances allow for installing products to the casing itself. However, when the annular clearance is smaller than ¾ in. a centraliser sub is required because the restriction area is simply too tight. In these cases, deepwater centraliser subs are manufactured by utilising the CentraMax CT one-piece centralisers and installing them directly onto the threaded sub body. The CentraMax Centraliser Subs are available with pull-through, rotating and push-in technology. Antelope aims to offer cost-effective and dependable solutions regardless of the challenges associated with reaching total depth and achieving a successful primary cement job.

Multilateral well construction has been on the rise as technology to support its drilling and construction has developed

rapidly over the past decades. Proven to increase total production from a single wellhead or well slot, decreasing total construction costs and

increasing ROI, the attraction is evident. But what happens when the well does not meet expectations? A typical method for gathering data to analyse the problem is running an e-line conveyed, production logging tool (PLT). But a way to consistently and effectively convey the

MULTILATERAL thinking

MULTILATERAL thinking

Brian K Sidle, Welltec, discusses developments

in production logging tools for

use in multilaterals.

| 37


PLTs into the multiple legs of the wellbore was missing – until now.

The attraction of multilateralsMaximum reservoir drainage from minimal locations is what lies behind the increased number of multilaterals that have been drilled and completed in the last few decades. Multilateral technology has evolved to offer not only the ability to drain reservoirs more efficiently but also to potentially drain multiple reservoirs simultaneously and with fewer surface locations.

Conventional wells were drilled vertically through the reservoir, producing only from the vertical surface area uncovered. In order to drain a large areal expanse, lots of wells were required. As technology advanced, however, operators began to drill deviated wells which by virtue of geometry alone increased the exposure to the reservoir and (ideally) increased production (Figure 1).

As technology continued to advance, horizontal wells became much more prevalent; today dominating the total number of wells drilled each year. This technique has had tremendous impact across the globe, turning previously uneconomical reservoirs into producers. Not only with the highly documented shale oil and gas successes of the US, but also in more classical lithology. A recent example from Norway which demonstrates this is the Smorbukk South Extension in the Asgard field. Originally discovered in 1985, its low permeability prevented it from being completed. Recently, however, long horizontal reservoir sections have been drilled accessing the tight reservoirs. One of these oil and gas producers was a multilateral with 17 060 ft of total reservoir exposure, a significant advancement from the days of vertical drilling.

Technology infrequently develops in isolation and improvements to horizontal drilling are no exception. Several other enablers evolved in parallel; the abilities to ‘see’ better and to ‘target’ better. This means that operators are now equipped with the ability to identify reservoirs (or sections of reservoirs) that were previously unidentified due to their size, characteristics or proximity to geological artifacts that would hide them. Once identified, the advances in ‘geosteeering,’ the ability to control the

bit during the drilling process, vastly increase the likelihood that these targets can be accessed.

Hence the simultaneous development of multiple technologies has led to the increased drilling and construction of horizontal, multilateral wells. Many smaller reservoirs or sections which were not economical to pursue individually due to their size or location can now be combined into a single well. Or if they could be accessed from a previously drilled well then they could be brought onto production as part of the existing infrastructure. These abilities have opened up a new mindset for well design as technology is now available to find, target and access multiple reservoirs or sections from a smaller number of well slots or pads, reducing the cost of well construction while increasing production and maximising reservoir drainage.

Data drives decisionsToday’s society is largely influenced and driven by data. This is also true when trying to optimise and increase total reservoir drainage. Much time and effort is spent modelling and designing the proper well placement in three dimensions for the best possible solution. Production and subsequently total drainage volume are impacted significantly by reservoir characteristics, but even more so when trying to combine multiple reservoirs in the same wellbore with the implementation of multilaterals.1

It is not only well placement considerations that benefit from correct data about the reservoir. Production data can help reduce uncertainties in reserve estimates, sweep efficiencies and in the case of multilaterals, pressure information which can aid in detecting cross flow or preventing production below the bubble point in the respective lateral.2

The data about the reservoirs can be acquired from a number of sources; seismic acquisition, during drilling or with open hole logging but one of the most common ways to acquire production data is via e-line conveyed PLTs. Fast, efficient and sensor heavy, these tools can provide real time measurements and surface read-out of fluid velocities, fluid types, borehole pressure and temperature, formation capture cross section and others. From these measurements a tremendous amount of information about the reservoir and even the completion design

Figure 1. Illustration of the evolution of increased reservoir contact.

Figure 2. Schematic of 2 ⅛ in. multilateral intervention tool.


can be computed. This insight can then be capitalised upon to aid in well optimisation, reservoir production and overall field management.

Staying ahead of the curve, Saudi Aramco has been investing heavily in a strategy for maximum reservoir connectivity or MRC. The Haradh III development, completed in 2006, demonstrated the success which could be achieved with extended reach, horizontal, multilateral wells.3 As a part of that strategy they would need to be able to gather production data in multilaterals to illuminate their decision making process; production data incorporated into reservoir modeling incorporated into field management. Many of these wells were fitted with sensors and controls to allow monitoring and corrective action, providing important data to fulfill the objectives outlined previously.

Not without challengesBut what about multilaterals wells that had been drilled prior to this or in other fields? What about wells where the economics were not conducive to a fully automated approach? Until recently there was no effective or efficient way to successfully enter the multilateral sections of wells with PLTs. Run on electric line (e-line) or slickline, the challenges were that the tools could not ‘see’ where the lateral junctions were nor could they orient themselves such that they would move out of the mainbore and into the lateral. This was compounded even further by the increased application of highly deviated and horizontal wellbores. Coiled tubing (CT) could convey PLTs into the wells but could not effectively guarantee orientation into the lateral section. One service provider did develop a mechanical, bottom orientation sub to locate and access laterals, but the tools that could be run in combination with it were limited.4

Again, Saudi Aramco remained firmly ahead of the curve in overcoming this challenge. Recognising the need to add laterals to existing wells for increased production and to assess the laterals in already existing wells, the EXPEC Advanced Research Centre Production Technology Team, in partnership with Welltec, in 2008 began to consider the challenges of entering laterals in order to take measurements.5 The objective was to develop a multilateral intervention tool that could be used to reliably access and gather data from the various multilaterals, aiding to further illuminate operators’ well, field and reservoir strategies.

The multilateral intervention toolThe multilateral intervention tool is built on an electromechanical platform that merges a sophisticated sensor package with an actuator system to detect and selectively enter laterals with e-line tools. Figure 2, shows a schematic of the 2 ⅛ in. OD, toolstring. It is comprised of a number of discrete components, as shown, which are detailed further below. One of the critical design elements was the capability of the tool to be able to work in combination with as many other tools as possible, thus ensuring wide versatility of the data which could be acquired during the lateral intervention. Hence the multilateral intervention tool can be run with any e-line company and convey their technology into the lateral section(s).

DevelopmentThe multilateral intervention tool went through a number of versions and trials before the final version was produced. Early versions of the tool were ‘wired,’ incorporating a feed-through

Figure 3. WHS log over a CH junction.

Figure 5. Comparison of mainbore and two laterals mapped by WUS - (A) top, and (B) bottom.

Figure 4. Graphic representation of the WUS.


wire that was required to extend through the third party tool. Although cumbersome and to some degree limiting the tools which could be run, it was essential for communicating with the portion of the tool responsible for controlling the orientation the tool moved in. Later, after further testing, a ‘wireless’ version of the tool was produced. The wireless iteration includes a wireless sub that allows communication to the steering section of the tool without requiring modifications to the third-party tool. This increased the overall flexibility of the tool and widens the range of applications for the operator.

Tool hardware

Well hardware scanner (WHS)Within a well completion the metallic components such as casing collars, perforation holes and sliding sleeves, create varying fluctuations in any electromagnetic field which is induced around them. The WHS monitors these magnetic variations very precisely to determine where exactly in the completion the toolstring is located and, more to the point, where the entrances to lateral windows are located. The WHS does this with a number of magnets and magnetic sensors placed in a grid pattern. Sensors then measure the magnetic field’s angle

in relation to the tool’s axis. The tool’s geometry relative to the surrounding casing material creates anomalies in the magnetic field. This information provides depth measurement, lateral window identification, lateral entry confirmation, tool speed and direction, and distinction between openhole (OH) and cased-hole (CH) environments. The tool also incorporates an accelerometer for inclination data. Figure 3 shows a representative WHS log over a CH lateral junction. The wide spacing, very low signal strength correlates to a junction where a lateral exits the main wellbore.

Well ultrasonic scanner (WUS)The WUS uses transducers and range-finding principles of time-of-flight measurement for ultrasonic signals to determine the casing environment. Ultrasonic transducers face outward from the outer diameter of the tool. These transmit signals sequentially while the transducers monitor the echo return time and amplitude response of the signals. This tool also incorporates an accelerometer for inclination. Figure 4 shows a graphic representation of the transducer signal emitting from the tool.

The transducers map the inside diameter of the wall opposite of the tool, thereby identifying the surrounding wellbore environment. Software located on the surface interprets the signals sent and received by the WUS to determine spots of diverging radius. This information identifies areas like washouts or sidetracks, for example. The WUS provides lateral window identification, lateral entry confirmation, orientation and the distinction between OH and CH environments. Figure 5 shows a comparison of multiple passes in the mainbore and two different laterals mapped by the WUS.

Wireless sub The wireless sub enables communication with the steering joint of the multilateral intervention tool wirelessly. This eliminates the need for 3rd party tools to be thru-wired, thus increasing the flexibility of what can be run in combination with the multilateral intervention tool. The wireless sub contains batteries for 12-hours to activate and steer the joint from surface in response to the tool outputs.

Electromechanical actuator – steering access sub (SAS) The SAS uses the information obtained from the sensors and known wall-path reference points to maneuver into the various laterals. This maneuver is completed in two steps. First, the steering joint pivots around its central axis towards the direction of the centre of the lateral. Next, the hydraulic piston in the SAS, controlled from surface, can orient the joint in any direction in 15˚increments.

Field trialsThe multilateral intervention tool went through a number of field trials on wells in Saudi Arabia entering many different wellbore types; some had been completed with a CH main bore and OH laterals while others had been completed with an OH main bore and OH laterals. These field trials proved the tool’s sensor ability to accurately scan the main bore at the depths required. The sensors were able to identify the position, depth and direction of the lateral window and guide the bottom hole assembly (BHA) into the required lateral in the wellbore. Additionally, the field

Figure 6. Graphs showing readouts from the WHS for a lateral. Inclination and depth were recorded and used to locate which lateral the tool was entering in the wellbore.

trials proved that any lateral could be re-accessed quickly and efficiently once the lateral was scanned.6

Case studyIn February 2015, in the southern region of Saudi Arabia, the 2 ⅛ in. multi-lateral intervention tool was run to access a highly deviated, slim hole motherbore and several laterals. The WHS and WUS in the sensor pack on the tool constantly scanned the wellbore environment over a series of up and down passes to identify the laterals’ depth and opening orientation, each lateral occurring at a different depth and inclination. The sensors in the multilateral intervention tool scanned the wellbore environment while the software on the surface recorded and mapped the location of the lateral, using depth and inclination as a coordinate system. Once the mainbore was effectively mapped, the tool returned to each lateral, entered it by using the SAS oriented in the correct position, effectively deploying the PLT. Sample graphs showing the depth vs inclination for two laterals from this operation are provided in Figure 6, demonstrating conclusively that both the laterals were entered.

The tool successfully deployed the PLT into lateral 5 for data acquisition. After the lateral was logged, the tool was pulled out to the mainbore where, using CT, it was pushed in the motherbore, logging from depths to confirm its location.

From surface data, total production from this well was estimated. The well was producing oil through a 4 ½ in. screen assembly and overall had very low watercut. Although it had a low water cut, this cased hole well provided an opportunity to capture a base-line production log in a recently worked over environment with this new technology.

Using the PLT, the data from the laterals was recorded and production estimates made for each lateral respectively. Pressure, temperature and fluid type were acquired over the depth intervals. With this baseline log of the initial production and the capability to reliably enter these laterals, the subsequent production from the laterals can be monitored in the future. The changes in this production profile over time will be interesting.

An increasing number of operations have been successfully completed using this technology. These operations have provided insights and information about the reservoirs and lateral sections of these wells, information that previously was unable to be gathered. This data can be used to enhance well and reservoir production as well as improve overall reservoir and field management.

ConclusionsMultilateral well construction has been on the rise as technology to improve drilling and construction has developed rapidly over the past decades. Proven to increase total production from a single wellhead or well slot, decreasing total construction costs and increasing ROI, multilaterals offer many advantages.

With the development of the multilateral intervention tool, the technology exists to reliably and effectively re-enter the lateral in order to acquire PLT data. This data can be used to increase the understanding of the reservoir sections which the lateral has entered. Uncertainties can be reduced in reserve estimates and sweep efficiencies, production can be optimised by the elimination of crossflows or producing below the bubble point, and well placement can be improved upon for

future drilling. The multilateral intervention tool can effectively be used by the operator to illuminate his well, field and reservoir development strategies.

Next stepsAcquiring the PLT data, reliably and efficiently is a quantum leap for improving the design and performance of multilaterals. But invariably, if the PLT data demonstrates problems, such as very high water production from one of the laterals, operators want to know how they can fix it. Although not covered in this article, the multilateral intervention tool is not limited to conveying just PLTs. For example, a setting tool assembly could be run and a plug set at depth in the lateral to provide water shut-off. Now that laterals can be accessed reliably with e-line tools, many previously impossible options become open for remedial intervention.

References 1. Statoil, http://www.statoil.com/en/NewsAndMedia/News/2015/

Pages/04Sep_Smoerbukk.aspx, (September, 2015).2. ‘Key Issues in Multilateral Technology’, Schlumberger, Oilfield Review,

(1998), pp. 14 - 28.3. Kuchuk, F. J., Onur, M., Hollaender, F., ‘Pressure Transient Formation and

Well Testing: Convolution, Deconvolution and Nonlinear Estimation’, Elsevier, (August, 2010).

4. Henni, A., ‘Saudi Aramco Wants Fields Fully Smart by 2017’, SPE News, http://www.spe.org/news/article/saudi-aramco-wants-fields-fully-smart-by-2017, (June, 2017).

5. EXPEC ARC Tests Downhole Tool, Saudi Aramco News, April 15, 2012 - http://www.aramcoexpats.com/articles/2012/04/expec-arc-tests-downhole-tool

6. Noui-Mehidi, M. N., Saeed, A. S., Al-Khamees, H., & Farouk, M., ‘Development and Field Trial of the Well-Lateral-Intervention Tool M’, Society of Petroleum Engineers. doi:10.2118/174095-PA, (April 1, 2015).

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W ith the current low oil and gas prices, operators are looking for ways to increase production from existing wells without incurring the expense of large-scale intervention and

stimulation programmes. Many oil companies have wells that are performing poorly or have stopped producing because of formation damage or plugged perforations caused by drilling mud, or by scale in the well near the production zone that impedes flow. Some wells drilled as injectors have so much formation damage that water cannot be injected through them. In many cases, the root cause of these problems is barite weighting material from the drilling mud or barium sulfate, strontium sulfate, magnesium and calcium carbonate scales caused by incompatible injected or connate water.

Barite and scales pose a difficult problem because they are very hard to remove. They are insoluble in hydrochloric acid (HCl) or hydrofluoric acid (HF) treatments, which may in fact make the problem even worse. Mechanical intervention can scrape away scale and barite that remains in the well, but cannot reach into perforation tunnels or into the near-wellbore matrix where barite damage seals off the formation and prevents flow into the well.

Chelation chemistryBeginning in the mid-1990s, operators have found that the right chelation chemicals, when applied properly, can dissolve barite

deposited by drilling mud and remove acid insoluble materials in well screens and tubing. High density converters (HDC) have achieved consistently favourable results in these applications.

Barite (barium sulfate) is highly insoluble in water or acid, but can be removed through chelation using high density converters. Chelation is a chemical reaction in which a chelating agent forms multiple bonds with metal ions to remove metal, in this case barium, from larger molecules. Barite particles as large as 70 microns can be reduced to particles 1 or 2 microns in diameter, which stay in suspension and easily flow out of the well without obstructing pore throats in the formation.

HDC is a blend of salts and acids with a pH higher than 12.5. It is not corrosive and has similar corrosion behaviour to seawater. It does not damage the formation, as proven by independent laboratory regained permeability tests. The chemical is a straight chemical, spotted ‘neat’ without water or additives, and left to soak for several hours to remove barite or scale. HDC treatments clean up perforated liners, wire wrap screens in open hole, and expandable screens clogged with barite left by drilling mud or scale.

The chemical has proven effective in removing field-grade barite, which is not pure barium sulfate, but can have up to 30% hematite. It removes drilling fluid solids and LCM weighted with barite, and cleans near-wellbore scales, which may be pure barium sulfate, pure strontium sulfate or magnesium sulfate.

RESTORING WELL

PRODUC

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PAUL W. BRADLEY AND TOM SHERWIN,

WELL FLOW INTERNATIONAL, BAHRAIN, EXPLAIN HOW

HIGH DENSITY CONVERTERS REMOVE BARITE AND

SCALE TO RESTORE WELL PRODUCTIVITY.

| 43


Risks of acid treatmentWhile acid treatment may be the right solution for many wells, there are also are risks associated with acid stimulation. HCl or HF acids used for well stimulation are hazardous chemicals that must be diluted with water typically down to 15% or less, so large volumes may be needed. Several additives are required to be blended into the acid treatment fluid, in large part to prevent the acid from damaging the pumping equipment and well tubulars. Also, acid jobs require mobilisation of large volumes of acid, frack tanks, pumping equipment and crews composed of up to 20 people. It is difficult to time acid jobs because acid has a short ‘shelf life.’ Once HCl has been blended with water and the required additives, the mixture only remains effective for two to three days as additives such as inhibitors degrade with time.

When acid is pumped into a well, it will flow along the path of least resistance, going places where it may not be needed. Many water based acid jobs cause formation damage, including clay hydration, which damages perforations and cuts off production. Acid can even soften carbonate formations to the point of collapse, so the well can no longer produce. Finally, a 3000 gal. acid treatment will need to be flowed back from the well, generating as much as 15 000 gal. of waste fluid that must be handled and disposed of safely. In wells where barite or related scales are the problem, acid can actually make matters worse, turning a low producing well into one that does not produce at all.

Advantages of treatmentNone of these problems apply to HDC treatments. The chemical requires no special handling, and is as safe to use as synthetic oil base mud. It is shipped in 55 gal. drums or small containers and is pumped ‘neat’ with no additives, in small volumes, typically 10 - 20 bbls per treatment. Pumping equipment needed for treatments may already be on the platform or at the land well’s location. Triplex mud pumps with two 10 bbl displacement tanks are generally sufficient to perform a treatment. No blenders or large crews of personnel are needed. Another benefit of the solution is that it can be stored on location for up to two years, enabling flexible scheduling of treatments.

In some instances the chemical can be pumped from the surface (bullheaded) to treat the production interval affected by the barite or scale. In more serious cases, when the specific location of well damage is known, it is more effective to spot the chemical directly at the target zone using coiled tubing and a jetting tool.

Whereas acid treatments require flow back of substantial amounts of waste fluid, the solution is applied in such low volumes that most of it dissipates into the formation. After treatment, HDC is an inert chemical and the portion that flows back does not need to be removed from produced fluid before refining.

The chemical is extremely effective at dissolving barium sulfate, especially in comparison to HCl treatments. In laboratory tests, an 18% HCL

treatment dissolves a negligible amount of barite, just 2 - 3 g/l of treating fluid. In contrast, when the chemical was first introduced in the 1990s, it dissolved 80 – 85 g of barium sulfate and scales for every litre of treatment chemical. Since then, HDC formulations have been improved. Laboratory tests show that the latest version of Well Flow International’s HDC®-3 dissolves over 300 g/l, and when used with a Koplus® LX pre-treatment, it can remove up to 380 g/l.

Laboratory tests show that the chelation reaction is particularly effective at dissolving relatively small barite particles – 20 to 30 microns in diameter – which have the greatest potential to bridge and close off pore throats in the formation. The chemical breaks these down to 1 - 2 micron particles that do not clog pore throats and remain in suspension as the treatment is flowed back from the well.

While other available barite dissolvers require high bottom hole temperatures to be effective, there is no minimum temperature for application of the chemical and it works well at 190˚F, which is typical in producing wells. The rate at which the chemical dissolves barite increases with temperature up to 400˚F, and 450˚F is the practical limit for HDC use.

In some older fields where water is injected to help maintain production, seawater or previously produced brines may be incompatible with reservoir chemistry, resulting in barium, strontium and calcium scales in perforations, screens and tubulars that can impede or shut off production.

HDC treatments, performed in two stages, clean barite and scale from completion components and then penetrate the perforation tunnels and reach up to one metre into the formation. HDC remains chemically active for up to 48 hours, compared to 6 - 12 hours for acid treatments, so that when the second stage is applied it forces the first stage chemicals, which are still partially active, into the formation behind the completion to achieve further cleaning.

Planning a well interventionTo plan a well intervention using HDC, the chemical provider works closely with the operator and the service company to review the history of any candidate wells, to determine what treatments have already taken place, and to decide whether the damaged zone needs to be isolated before treatment. If there are asphaltenes present in the well, it must be pre-flushed to expose the residual barite, filter cake or scale so it can be effectively treated. Well Flow International uses TarClean™ and Super Pickle® treatments, which do not damage elastomers or other well components, to expose the barite contamination. The subsequent treatment is designed to match well conditions and usually involves two stages of soaking performed in sequence.

The first application is pumped into the well, either bullheaded or spotted by coiled tubing, at a rate of less than one bbl/min. To treat a 30 m perforated interval, the coiled tubing unit would be used to spot the chemical at the base of the zone, gradually moving up to the top of the interval, and then repeating this treatment pass to provide assurance that the zone is filled with the treatment chemical.

The first stage soaks for 6 - 8 hours while the chemical reacts with contamination in the wellbore and in the adjacent formation. During the first soak, the chelation reaction separates the barium and sulfur to break down the barite in the wellbore and extending out approximately one metre into the formation where most of the blockage to production has occurred. Then, while the HDC from the first soak is still about 30% active, a second soak is spotted using the same method. The second soak pushes the first wave of chemical into the formation and makes sure the perforations and well screens are thoroughly treated. The second soak will also remove any barite and solids that were not treated by the initial dose of HDC.

After the second chemical placement, the chemical will finish reacting with the barite and scale in 18 - 24 hours. At this point it becomes inert and

Figure 1. HDC-3 dissolves over 300 g/l of barium sulfate and scales, and when used with a Koplus LX pre-treatment, it can remove up to 380 g/l.

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can be flowed back to surface without damaging equipment, and without handling issues associated with acid treatment waste fluid.

Field results Table 1 summarises 12 examples of successful treatments using HDC to remove barite and scale and in some cases dramatically increasing production or injection rates. Applications in oil and gas

Table 1. HDC barite dissolver case histories.

Location Well type Problem Treatment Deployment Results

UK North Sea 28 000 extended reach well with perforated liner.

Barite from OBM caused severe skin damage. Well under-produced from the outset. High water cut, caused barium, strontium sulfate and carbonate scales that impaired production.

HDC I and HDC II designed for barite and scale.

Bullheaded, 12 hour soak.

Pre-treatment production:1550 bpd.2424 boe/d.

After treatment:2245 bpd4997 boe/d

Stabilised production:2340 bpd3984 boe/dNet increase in oil production was 51%. Removed 156 kg mud-grade barite and 50 kg of barium scale.

UK North Sea Three horizontal wells with ESP and 900 ft of screens.

Dolomite/barite mud solids blocked off screens and ESP. Problem compounded by HCI and U104-U105 treatments to remove carbonate scale.

Koplus LO pumped ahead of HDC Mark II.

Bullheaded. First HDC soak: 8 - 12 hours. Second HDC soak: 24 hours.

First well:

Pre treatment production:11 000 boe/dAfter treatment production: 22 000 boe/d.

Two more ESP wells treated, contributing 60 000 boe/d.

UK North Sea

New gravel-packed injector well, moderate temperature of 148˚F.

Operator attempted to inject through well without removing SBM mud cake. Injection significantly impeded.

HDC Xream and Mark II. Coiled tubing placement, 24 hour soak.

Removed all filter cake even at low bottomhole temperature.

UK North Sea

Oil producer completed with well screens, moderate temperature of 148˚F.

Barite from OBM blocked screen and caused skin damage.

HDC Mark II, 4000I.Bullheaded, cleaned up under its own pressure after 48 hours.

Production doubled from pre-treatment levels, attaining theoretical 90% rate.

UK North Sea

Horizontal oil producer with 2000 ft reservoir section, collapsed shale left only 400 ft able to produce.

SBM compressed around the well screen, barite solids drop-out in formation. No results from prior solvent/ nanowash treatment.

Koplus LO pre-flush, HDC Mark II with calcium carbonate dissolver.

Bullheaded, three treatments.

PI increased from 1.5 to 7.5.

Production before treatment: 400 boe/d. Production after treatment: 4000 boe/d.

LouisianaHPHT gas well, 12 000 psi THP 415˚F.

Well experienced severe mud losses during drilling, stopped by massive LCM pills. HCI and HF/HCI treatments could not remove damage, liquefying formation.

HDC Mark II with Koplus LO preflus.

Squeezed into well. Two-stage soak.

Well produced 18 million ft3 before metal and gravel blocked choke and tubing. Demonstrated that gross damage to well could be reversed.

Malaysia

High temperature gas well, 325˚F deviated, dual string completion, perforated liner.

Originally designed to produce 25 million ft3 but only produced 10 million ft3. OBM was pumped to kill well. Perforations in both zones buried in settled barite. Acid treatment left well producing only 1 million ft3.

HDC Mark II, bullheaded through short string.

Bullheaded through short string. 26 hour soak. CTU used for N2 gas lift.

Production increased to 7 million ft3/d and 5 m3/d condensate and 1228 kg of barite dissolved.

Malaysia

High temperature gas well, 325˚F deviated, dual string completion, perforated liner.

Originally designed to produce 50 million ft3/d but only made 20 million ft3. Well impaired by settled OBM solids. During a CT acid-washing job, a jetting head was lost and production rates remained poor.

HDC Mark II after Koplus LO and Super Pickle pre-flush.

Bullheaded into lower zone. The well recovered under its own pressure and was placed on stream at 45 million ft3.

ThailandMonobore newly drilled injector with perforated liner.

Drilled with OBM, the well failed to inject after perforation, blocked with barite.

HDC Mark II, in two stages.

Placed with coiled tubing unit, first soak eight hours, second soak 24 hours. Gas lifted with CTU.

Well went operational injecting 8500 boe/d at 1500 psi.

Nigeria

Horizontal well with 2467 ft section completed with open hole slotted liner.

Well had no production due to OBM solids and damage from poor acid job. Two attempts failed to unload well.

Super Pickle/Koplus LO pill followed by HDC Mark II.

Coiled tubing placement. Soaked for 24 hours. N2 used to lift well.

Well flowed at 2700 bpd at 650 psi and stabilised at 2500 bpd.

Nigeria Newly drilled producer with well screens in open hole. 160˚F BHT.

Well initially shut in for 152 days because of local unrest, then produced poorly. Formation impaired with mud solids. Fish left in well during stimulation attempt, resulting in no production.

Koplus LO and Super Pickle pre-flush followed by HDC Mark II.

Coiled tubing run to top of fish, then treatment was bullheaded.

Production increased from 0 bpd to 3000 bpd.

Australia HPHT geothermal well, vertical.

Fish lodged in settled barite and through milled bridge plug.

HDC Mark II, spotted three times.

Bullheaded. Fish, released from barite, fell to bottom of well. No further fishing or milling required.

fields around the world have included extended reach offshore wells with severe oil based mud skin damage, horizontal wells with clogged screens and electrical submersible pumps, injector wells clogged with barite, and high temperature gas wells whose production was impaired by mud filter cake and scale. In these cases, HDC has been a practical solution for dealing with barite problems.

Although the recent commodity price fluctuations have exposed the role of geo-politics, world economies and commodity trading in the life cycle of assets, a limited number of field development studies have considered the impact of commodity cycles on the

development of in-fill wells. These commodity price fluctuations have resulted in a reduction in drilling and completions activities across the United States. This further implies that in most unconventional plays throughout the US, in-fill well completion (and thus production) will be delayed. This article highlights some of the considerations that should be made when evaluating the well completion strategy with focus on two unconventional plays, the Bakken and the Eagle Ford.

The key objective of studying the Bakken and Eagle Ford was to model the well performance of the parent wells with the aim of predicting in-fill well performance. Petrophysical and Geomechanical models were developed using data-rich parent well data-sets. Based on the calibration data available (core and logs) numerous static models are generated to capture the range of possible interpretations that honour the calibration data. These models were validated with more calibration data in completions and reservoir domains to reduce the uncertainty space via history matching real data (production or fracture treatments). Once, the parent well models have been validated (by matching well performance history), in-fill modelling and optimisation can proceed. Since the two assets (Bakken and Eagle Ford) are at significantly different portions of the development cycle, the Bakken dataset has the luxury of modelling and matching the performance of the parent and in-fill wells whereas, the Eagle Ford portion of this study focuses primarily on forward modelling and optimising the in-fill well completions.

Bakken system parent well modelling

Petrophysics Petrophysical evaluation indicates that the average of porosity and water saturation is 8% and 50% respectively for the Middle Bakken. Average Klinkenberg permeability for the

Bilu V. Cherian, Sanjel Corporation, Mathew McCleary

and Samuel Fluckiger, SM Energy, discuss challenges of

in-fill development.

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entire Middle Bakken is 0.02 mD. Mercury injection capillary pressure (MICP) data indicated that irreducible water saturation was between 30 - 40% for rock with and residual oil between 30 - 40%. Petrophysical evaluation suggests that the Upper part of the Three Forks had oil potential.

Average reservoir parameters for the upper Three Forks facies are 8% porosity, 60% water saturation and permeability < 0.02 mD. Irreducible water saturation was estimated as 45 - 55% for good and poor quality rock respectively; residual oil is estimated at 40 - 55% for good and poor quality rock respectively. In this area, the middle and lower Three-Forks have higher water saturation, with very low permeability streaks (< 0.007 mD).

GeomechanicsA key parameter in the iteration of various mechanical earth models (MEMs) was the pore-pressure profiles. A pore pressure transition region into the Lodgepole (Scallion formation), was created where a linear pressure increase from salt water gradient up to the estimated pore-pressure of the Upper Bakken Shale. For the TRFK, a linear decrease of pore-pressure from over-pressured in the Lower Bakken Shale to normal pressure was generated within the first 100 ft. The pore pressure remained elevated across the pronghorn and first two TRFK benches, and then reduced back to a salt-water gradient for the remaining TRFK benches.

Fracture modelling - Middle BakkenFor the Middle Bakken: Micro-seismic and the diagnostic fluid injection test (DFIT) data together with interference information from 355 offset fractures with 47 communication events, constrained the expected geometry height growth and an expected fracture length, in both the MB and TRFK. For the Three Forks: micro-seismic data and interference information from 134 fractures with 28 communication events constrained an expected geometry height above and below the TRFK, and a minimum expected fracture length in the MB and the TRFK.

Analysis on the Bakken wells in the study area indicated high (> 1500 psi) net-pressures and low breakdowns. This implies that a plug-and-perf (PnP) completion methodology could yield success by enabling multiple perforating clusters (within a stage) to breakdown,

especially when high pump rates (typical of slickwaters) are utilised (Figure 1). When parent well sliding-sleeve (SS) treatments were modelled (Figure 2), a large single dominant fracture was observed (via fracture modelling and production modelling). When parent well PnP treatments were modelled (in the same area), propagation of multiple fractures was confirmed by both fracture and production modelling. Fracture modelling indicated that two dominant fractures were propagating.

Production modelling For the Bakken model, the upper and lower shale were modelled, together with the Middle Bakken. Daily bottom-hole pressures (BHP) were computed and calibrated to BHP gauge data on offset wells to select the appropriate flow – correlation. Compaction curves were generated from core data and utilised to model fracture conductivity and permeability degradation. The SS Middle Bakken well has a permeability of >0.01 mD, maximum fracture half-length of 250 ft and a dimensionless fracture conductivity that reduces from seven to four. Flowing bottom-hole gauge data was used to constrain the history match (Figure 3). Compaction curves from core and proppant were utilised to model degradation of proppant conductivity and rock compaction (permeability/porosity reduction). An ‘additional damage’ factor (using compaction curves) had to be added after two years of production to match the fluid level measurements. This damage increased with time. The initial hypothesis was proppant crushing (since effective stresses were close to 6000 psi – crushing pressure of sand).

Figure 2. Comparison of sliding-sleeve (single fracture) and plug-and-perf geometries (dominant cluster of three).

Figure 1. Typical fracture geometry variation expected in a stage.


Fracture and production modelling - Three ForksFracture modelling in the Three Forks indicated that the SS treatments connected into the Middle Bakken due to the creation of a large single dominant fracture. Production modelling confirmed that the connection to the Middle Bakken was stress sensitive and deteriorated within the first three months of production (Figure 4). Flowing bottomhole pressure and water cut indicated that this well was connected to the Middle Bakken for a significantly longer time than expected (Aman, 2010). The SS Three Forks well had a permeability less than 0.005 mD (top 10 layers of the Three Forks), fracture half-lengths ranging from 100 - 150 ft. and a dimensionless conductivity greater than 10 (Figure 4). The short fracture half-lengths observed were consistent with fracture modelling. In the PnP Three Forks treatments, connectivity to the Middle Bakken was poor due to the addition of multiple clusters per stage (via PnP) and subsequent reduction in job volume per fracture propagating in a stage.

Optimisation with no parent well influenceOnce the multi-domain iteration was complete and models with quantified uncertainty ranges built, predictive modelling could begin. For the fracture length and number of stages to be optimised, the bounding (offset) wells were used to ensure accurate forecasting on long-term performance of the middle well.

Forward modelling (optimisation) runs indicated that a hybrid cluster approach could be utilised to maximise fracture propagation success. Optimal job size volumes, fracture treatment rates and stage count were determined for the Middle Bakken and Three Forks. The results indicate that the maximum production is obtained by increasing the number of fractures in a well from X to 4X. Thus, if a SS completion system was utilised, 4X sleeves with entry-points must be installed. If a PnP approach is utilised, fracture modelling has demonstrated the pump rate required to propagate two to five clusters and the resulting job size requirements.3 Optimisation also shows that past 4X fractures, further production uplift can be achieved from increased fracture length (deployment of modified job design).

Bakken system in-fill well/depletion modelling The in-fill interference of a parent Middle Bakken well (by an offset Middle Bakken well) was fracture modelled and production matched (Figure 3). Production matching of the in-fill drilling and interference of this parent well (by an offset well) confirmed that scale was the damage mechanism since a post-interference match was re-established once this ‘additional damage’ was removed. This observation and the scale treatment history of this well resulted in the hypothesis that the relatively fresh water from the fracture treatments dissolved the scale in the parent well. Numerous cases of in-fill interference have been reported in the basin over the past few years. To date the impacts of interference on the parent well have been primarily related to additional ‘stimulation’. Modelling results indicate

that it is unlikely to have sufficient amounts of proppant to travel those distances even under asymmetrical conditions. Thus, scale dissolution may also be contributing to the sustained production enhancement of the parent wells.

As a result of poor productivity in the Three Forks interval, minor fracture asymmetry was observed from the in-fill well. This is due to the poor productivity of the Three Forks interval in the area. However, interference is caused from an upper reservoir (Middle Bakken). To date little research has been performed to understand the productivity and the extent of depletion in the Upper and Lower Bakken Shale.

As production reduces stress but increases effective stress it can be expected that simultaneous fracture operations (driving efficiency) are created to form a similar asymmetry and lack of increased containment. Completing Middle Bakken wells, followed immediately/shortly by an in-fill Three-Forks will result in containment.

Eagle Ford system parent well modelling Workflows and procedures for the characterisation and testing (calibration requirements) of rocks that are both the source rock and reservoir have evolved significantly from those used in conventional plays. Since, pressure, permeability and saturation are much more challenging to measure in thin-bedded unconventional reservoirs using

Figure 4. Pressure and production history match – the effect of bashing noted at the end of history.

Figure 3. Pressure and production history match – the effect of bashing noted at the end of history.


standing logging tools only, multiple measurements and models must be created with the aim of reducing uncertainty.

PetrophysicsPetrophysical evaluation indicates that the average of porosity and water saturation were greater than 9% and less than 18% respectively. The petrophysical model results show that the permeability ranged from 100 – 900 nD.

GeomechanicsThe Ben Eaton stress model with a variable anisotropic Biot model was utilised using calibration from core. An iterative approach engaging fracture modelling, constrained by log responses (that imply possible pore pressure transitions) resulted in an estimation of pore pressure gradient from the Austin Chalk into the Buda.

Fracture and production modelling In the Eagle Ford dataset, since little in-fill drilling has occurred; limited interference or micro-seismic data exists. A similar workflow utilised in the Bakken Three Forks was utilised to understand fracture geometry and constrain production history match parameters. High net-pressures (>1200 psi during treatment and > 500 psi in the DFIT) in the Eagle Ford enabled the breakdown of multiple clusters. Modelling indicates that some optimisation opportunities still exist within the multi-cluster fracturing scenarios since only 30 - 50% of the fractures within a stage can create dominant fractures. Modelling indicates that if a lateral porpoises across ‘critical’ stress units, the propagation and connectivity within the reservoir changes significantly. Production history matches honoured the relative change in fracture half-lengths within a stage due to limited entry or stress shadowing. Productive fracture half-lengths varied from 50 - 200 ft and permeability ranges from 70 - 500 nD. More than two years of production history was matched on two parent wells.

The importance of layering effects causing pinching and preferential propagation in most unconventional plays are forcing operators to realise that draining a thick reservoir column with multiple laterals can improve production performance significantly.

Eagle Ford system in-fill well/depletion modelling Figures 3 and 4 demonstrate the early impact of in-fill drilling and interference in the Bakken and Woodford. Overestimation of vertical connectivity across the entire column can result in the under-estimation of the depletion sink.

Once production history matching was performed on the parent well, the new stress state was re-computed to model the impact of

fracture propagation between two parent wells. Fracture modelling indicates that production from the upper benches can create improved containment with similar effectiveness using smaller designs and create weak points that result in height growth that would otherwise not be observed under virgin conditions. Based on the forward models, in-fill treatments were designed to minimise asymmetrical effects and direct interference with the offset wells. Figure 5 shows the impact of a larger design-optimised design not shown. Preliminary production results are encouraging and continued monitoring, testing and evaluation will take place.

Conclusions This study demonstrated that parent well modelling was critical to understanding which wells are within the region of interference. The success of the in-fill well completion design is determined by the ability to characterise the current production system in order to understand the extent of depletion. Modelling was utilised to understand the changes required in operational activities when performing in-fill development. The observation of the potential challenges and re-design of the completion program has resulted in significant success. The introduction of a model based approach to improve decision making will reduce the cycle time between the initial wells drilled and the optimal development strategy.

AcknowledgementsSM Energy: Nathan Nieswiadomy, Brent Bundy, Sarah Edwards.

Sanjel Corporation: Rafif Rifia, Kristina Kublik, Santhosh Narasimhan, James Gray, Olubiyi Olaoye, Hamza Shaikh.

References1. US Energy Information Administration. http://www.eia.gov/oil_gas/rpd/shale_

gas.pdf, (April 13, 2015).2. Cherian, B.V, Nichols, C.M., Panjaitan, M.L., Krishnamurthy, J.K., Sitchler,

J., ‘Asset Development Drivers in the Bakken and Three Forks’, SPE 163855; SPE Hydraulic Fracturing Technology Conference, The Woodlands, TX, USA, (4 - 6 February, 2013).

3. Mukherjee, H., Poe Jr., B.D. Heidt, J.H., Watson, T.B., and Baree, R.D., ‘Effect of Pressure Depletion on Fracture Geometry Evolution and Production Performance’, SPE 65064, SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, (22 - 25 September, 1995).

4. Ajani, A., Kelkar, M., The University of Tulsa, ‘Interference study in Shale Plays’, SPE 151045, SPE Hydraulic Fracturing Technology Conference, the Woodlands, Texas, (6 - 8 February, 2012).

5. Waters, G.A., Dean, B.K., Downie, R.C., Kerrihard, K.J., Austbo, L., McPherson, B, ‘Simultaneous Hydraulic Fracturing of Adjacent Horizontal Wells in the Woodford Shale’, SPE 119635; SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, (19 - 21 January, 2014).

6. Wheaton, B., Miskimins, J., Wood, D., Lowe, T., Barree R., ‘Integration of Distributed Temperature and Distributed Acoustic Survey Results with Hydraulic Fracture Modelling: A Case Study in the Woodford Shale’, URTeC 1922140. SPE/AAPG/SEG Unconventional Resources Technology Conference, Denver, Colorado, USA, (25 - 27 August, 2014).

7. Lalehrokh, F., and Bouma, J., Talizman Energy USA, ‘Well Spacing in Eagle Ford’, SPE 171640, SPE/CSUR Unconventional Resources Conference – Canada, Calgary, Alberta, Canada, (30 September - 2 October).

8. Ganpule, S., Srinivasan, K., Izykowski, T., Luneau, L., and Gomez, E., ‘Impact of Geomechanics on Well Completion and Asset Development in the Bakken Formation’, SPE-173329. SPE Hydraulic Fracturing Technology Conference, the Woodlands, Texas, (3 - 5 February, 2015).

9. Heller, R., Vermylen, J., and Zoback, M., ‘Experimental investigation of matrix permeability of gas shales’, AAPG Bulletin, v. 98, no. 5 (May, 2014), pp. 975 - 995.

10. Narasimhan, S., McCleary, M., Fluckiger, S., Gray, J., Cherian, B., Shaikh, H., ‘Using the wrong method to estimate stresses from depletion causes significant errors in predicting wellbore integrity and fracture geometry’, SPE 173310, SPE Eastern Regional Meeting held in Morgantown, West Virginia, USA, (13 - 15 October, 2015).

Figure 5. Example of depletion profile from assymetric propagation and fracture geometry as a result of the in-fill drilling between two parent wells in the Eagle Ford.

NoteTo read this article online, along with the full reference list, please visit: http://bit.ly/24t20iE

Everyone in and near the oil industry today is defined as much by the money they save as by how much they produce. With oil prices shivering in the US$40s for a very long season,

companies up and down the food chain are looking to cost savings and efficiencies in order to keep going.

But cost savings must not come at the expense of results. Therefore, any new procedure that promises to cut costs and improve results will merit a close look from companies needing those services.

In the category of frack fluid chemicals, Bosque Systems in 2015 released a service that promises to both reduce costs and improve production. The OptiFluids™ service aims to do this by offering chemicals as a separate product from the package put forth by the company pumping the frack water downhole.

Typically, frack chemicals pass through the hands of a chemical reseller then the frack company on their way into the formation – stops that each add costs to the producer. Because the frack job is usually a turnkey operation, operators often accept a predetermined mix for each completion without regard for individual downhole conditions that may require a different formula in order to maximise production.

Because the company has experience treating produced and brackish water for re-use in fracturing, waterflooding and other oilfield use and because members of its leadership team have experience with chemical mix design, clients began requesting help with frack fluid formulation. Some clients had become frustrated with the lack of choice offered by their horsepower providers and, because they were already Bosque customers for water treatment, looked to the company for solutions with frack chemicals.

The company’s engineers had already developed chemical programmes designed to prepare water for reuse, especially in the Permian Basin of west Texas and Southeast New Mexico. Because fresh water resources are limited in those areas, producers there found it necessary to recycle produced water. Without treatment, that water damages the horsepower providers’ pumps and equipment, so the company developed chemical treatments that would clean up the water to make it useful.

In February of 2015 meetings began with chemical suppliers in order to determine the lowest-cost supply chain options for getting the top-performing actives in the industry. During that time engineers started the process of designing chemical feed units, based on

CUTTING CHEMICAL

PAUL WISEMAN, BOSQUE SYSTEMS, USA, SHOWS HOW UNBUNDLING CHEMICALS FROM THE FRACK PACKAGE GIVES PRODUCERS MORE CONTROL AND REDUCES COSTS.

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industry best practices, which would deliver the product mix in the field.

After field testing chemical mixes in a variety of areas with varying formations, temperatures and other conditions, the company began formulating OptiFluid packages appropriate for each set of conditions. This would give operators wells with fewer issues and better production, while saving 30 - 40% on the cost of the chemicals.

From those first chemical company meetings to the initial field use about four months elapsed.

To arrive at the proper chemical mix for each well, the service engineers meet with the producer’s frack engineers and share their expertise in frack fluid performance and compatibility design. They learn what the producer is currently using and the extent to which that design is bringing the desired results. The team makes recommendations based on all these factors and follows that up with fluid performance and compatibility testing. Armed with this data the producer can make an informed decision regarding the final formula.

Because chemicals such as high TDS friction reducers, nanosurfactants, compatible scale inhibitors and biocides and others have traditionally been delivered as part of a package, without discussion, the idea of discussing and choosing a chemical mix is often a new idea to producers. Even wells in the same field and the same formation may require different frack packages to achieve optimal production.

Frack chemicals amount to approximately 5% of the total fracturing costs, but when an overall job runs into the millions, chemicals still amount to hundreds of thousands of dollars. In 2014 US producers spent over US$9 billion in frack chemicals. Reducing those numbers by 30 to 40% of that is significant even for individual producers when calculated over a large number of wells. Some producers have reported that this saves them enough money to allow them to add one or more wells to their drilling budget over the course of a year’s time.

OptiFluids also has the ability to measure exact amounts of the required chemicals in order to give the best production results and to provide accurate billing. The system utilises a two-axle 48 ft-long drop-deck flatbed trailer with a 12 - 330 g IBC tote capacity that carries two 18 hour life diesel generators running 10 positive displacement pumps to deliver the fluids. The equipment is controlled by an ESS wireless and analogue chemical pump control system, including a data logger that uses a cellular network to communicate to a customer-login website for reporting purposes. The system can pump one chemical up to 12.5 gpt or 10 separate chemicals at a rate of 1.25 gpt each.

Precise chemical measures are delivered through a mass balance feed system that follows the job’s

predetermined recommendations. Operators observing a flow meter can dial the pumps up or down in order to get dosages within just over 1 ml of the numbers in the fluid design.

Operation observation is the first layer of a three-level monitoring system. Second, Optifluids uses a calculated formula based on a total flow rate, which tells the operator the expected delivery quantity. Third, finely-tuned flow meters show the amount of chemicals actually pumped.

MonitoringCareful monitoring of delivery allows the mix to be altered if conditions warrant. For example, the design may call for 1000 g of friction reducer. But if engineers determine that friction levels are lower than expected they can reduce the amount in the mix and thereby save the customer money.

On the other hand, engineers may see that increasing the friction reducer will lower the amount of horsepower needed for the job. The savings in horsepower cost more than offset the additional chemical charges.

Bosque’s website sends the data to the on-site frack manager, who delivers the real time data as well as final reports to the operator, showing that the exact formula was indeed delivered into the well. Producers have greatly appreciated the completeness and accuracy of the data provided.

Achieving ease-of-use was another goal of the OptiFluid designers. Systems with this much sophistication and flexibility also frequently require extensive training or expertise to operate. Early returns for this system reveal an appreciation for its simplicity and its economy of operation.

As the company began to speak to other clients about the system, some expressed hesitation at the idea of unbundling for two reasons. First, this was a new idea and, because these companies had not thought of separating the pumps from the product before, it took some getting used to. Second, they were concerned about having additional equipment and people at the well site.

But those who tried the system quickly gained an appreciation for the cost savings, the precise chemical delivery and the information provided.

One client, who was paying approximately US$9/gal. for frack chemicals, is saving 40% on the total package, which includes chemical prices, amount of chemicals used and labour. This reduction in cost saves US$3.5 million in 2015 alone. This will allow the producer to drill one more well than they had previously had in their budget for the year.

It is important to note that the exact price per gallon of frack fluid is deemed most viable for each well, along with the price offered by the manufacturer at the time Bosque makes the purchase.

End users have also seen economic benefits from increased production due to careful selection of frack fluids. By utilising Optifluids trailers, one producer can expect a percentage difference in oil recovery.

Conclusion During the four years or so when oil prices hovered around US$100/bbl, few companies looked closely at a cost so seemingly small as frack fluids. But with 2015’s precipitous drop, every ledger entry, every penny spent has gotten a much closer look.

OptiFluids can not only reduces costs, but it can provide operators with more precise control over the frack process with the potential for improving results as well. This two-phase benefit has resonated well in the industry at this time. Figure 1. Bosque Optifluids mobile stationary unit.

As the price of oil continues its downward trend and E&P budgets continue to shrink, smart operators are looking for ways to maximise production and extend the productive life

of assets already in place. In many cases, production is dependent upon maximising water injection to maintain reservoir pressure. Often however, despite good water handling processes, water injectivity can be reduced significantly over time through the build-up of deposits in the near wellbore region and in the injection infrastructure.

When injectivity cannot be maintained, producing wells have to be shut in and cleaned, resulting in a significant loss of revenue. Cleaning typically involves hazardous solvents and/or acids to remove the deposits that are blocking pore throats and coating the injection infrastructure. Depending upon the severity of the problem and the efficiency of the programme, this intervention may have to be repeated after only a few weeks or months.

These deposits typically contain a mixture of water insoluble components that are carried through the production system.

DR. DAVID HORSUP AND DR. CALEB CLARK, NALCO CHAMPION, USA, INTRODUCE A MULTI-FUNCTIONAL TECHNOLOGY DESIGNED TO MAXIMISE WATER INJECTIVITY AND OIL PRODUCTION

WHILST EXTENDING ASSET INTEGRITY.

MAXIMISING PRODUCTION AND ASSET LIFE

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The main components are hydrocarbons, iron sulfides, asphaltenes, sand, and clays (The relative ratio of each component will be system specific). This combination results in an oily sludge that blocks pore throats and coats the injection system. This oily sludge can also provide an environment conducive to under-deposit corrosion resulting in accelerated pipe failures.

Typical corrosion prevention involves injecting corrosion inhibitors into production fluids and can be an extremely cost-effective means of mitigating corrosion in carbon steel pipelines. Unfortunately, the inhibitors are worthless if they cannot reach the pipe wall. This is because this oily sludge forms a tenacious barrier that cannot be penetrated by most corrosion inhibitors. It acts as a parasitic surface adsorbing the inhibitor from the bulk liquid phase. Consequently, these deposits can create significant integrity management challenges.

The need for a different solutionThe importance of keeping production equipment clean and the difficulty in dealing with this oily sludge is clear. While the thickness of oily sludge in a pipeline may range from only a few millimetres to several centimetres or more, the outcome is the same: the sludge may adsorb significant quantities of corrosion inhibitor, preventing the inhibitor from reaching the pipe wall.

Thus the sludge deposits have to be physically removed from the pipeline, typically through maintenance pigging operations. However, in many fields with an older infrastructure, pig launchers and receivers may not be installed, and even if they are, the pipe configuration may have changed such that there is pipe of varying diameter along the same line. It is often very difficult, if not impossible, to pig a line like that. Pigging operations can also result in process upsets, lost production, significant Opex costs, and EH&S challenges.

Recognising the importance of tackling this problem more than 10 years ago, Nalco Champion began a thorough research effort, aimed at understanding the factors involved in successfully removing oily sludge by chemical means, and then developing a formulation that could effectively remove this sludge while also mitigating aggressive corrosion. The company’s field operators in North America dealing with the problem of corrosion under sludge provided samples to staff scientists to assist with the research effort. Compositional analysis revealed that the majority (40%) of the sludge was hydrocarbon, which was essentially the ‘glue’ holding the solids in the sludge together (Figure 1).

Research efforts result in a multi-functional technologyBy focusing on a way to desorb or remove the hydrocarbon ‘glue’, the remaining solids should be carried off the surface as well, allowing the corrosion inhibitor to reach the pipe wall. Thus after extensive research and testing, a multi-functional product was developed that was seen to be significantly superior to conventional corrosion inhibitors at removing oily deposits. The removed oil is emulsified as fine droplets in the circulating brine phase. Since the oil is the ‘glue’ holding the solid components of the deposit together, once it is removed, the solids can also readily be removed and are held in suspension in the brine. Reducing this obstruction enabled a significant increase in water injectivity and consequently oil production.

In an initial laboratory test, at a dosage of 80 ppm, 99% of the oily sludge was removed within 10 minutes (Figure 2). The corrosion inhibition performance was further evaluated in a series of laboratory tests. In virtually all studies performed, the new product was seen to exhibit a performance superior to an established ‘best in class’ inhibitor. Even under shear stresses of 800 Pa, the product exhibited 95% protection at a dosage of 25 ppm. This performance was also validated in field evaluations.

This product was named Clean n Cor®. When introduced into a water injection system, the product is designed to clean away oily Figure 1. Compositional analysis of field sample of oily sludge.

Figure 2. Photos of initial Nalco Champion new product lab test results. The image on the left shows that the best in-class inhibitor removed only 30% of oily buildup after two hours. The image on the right shows that after 10 minutes, the Clean n Cor technology removed 99% of the buildup dosage at 80 ppm. In both low and high shear tests. The new technology performed at least as well as the best in-class product, providing greater than 95% protection efficiency at low dosages between 5 and 25 ppm.

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sludge deposits, prevent new deposits from forming, maximise water injectivity and oil production and provide corrosion inhibition to the injection infrastructure.

Product evolution and expansion to meet growing market needsOver time, field experience and research teams have evolved the technology into an array of products tailored to remediate the various deposit compositions found in the oilfield as well as other complex operational conditions. As previously mentioned, this technology was designed to treat systems heavily fouled by hydrocarbon. While hydrocarbon is often a deposit’s binding agent, system fouling is regularly compounded by other solids present in the deposit matrix. To address these additional challenges, several product line extensions have been developed. The product line contains the original high performance components for hydrocarbon fouling as well as chemistries targeting: iron sulfide deposits, paraffin/asphaltene control, scale inhibition and winterising, water floods, and ongoing system maintenance.

In addition to advanced chemical composition, the technology incorporates hands-on technical expertise and in-field monitoring to provide a comprehensive treatment solution. In water injection wells, it removes deposits from inner pipe walls and filter equipment, provides continuous cleaning at the formation face, and prevents aggressive corrosion from taking place. This results in increased injectivity, more consistent injection rates, and maximum injection capacity for improved production. For heavily soiled or ageing assets, the company’s technologies help operators maximise production and extend asset life. In pipeline applications, it prevents under-deposit corrosion while reducing maintenance, pigging costs, and associated downtime and labour. Furthermore, the use of the technology for injectivity improvement in waterflooding can help operators accelerate the recovery of their proven reserves and can also clean the wellbore and enhance the ability of water to enter the formation. Increasing injection rates will increase offset oil production rates and accelerate reserves recovery. In addition, using the technology as a pretreatment or additive should improve the effectiveness of traditional EOR techniques. Cleaning out the near wellbore will improve the injectivity of EOR chemicals by allowing the chemicals to penetrate into areas in the formation previously unaccesable due to deposits. Increasing water and chemical injectivity during EOR will accelerate the oil production response resulting in improved economics.

Proven results In one customer’s water injection system, this level of oily sludge removal translated to 75% more water being injected, resulting in increased oil production and an 800% return on investment. Once the oily sludge had been removed, Clean n Cor prevented it from re-adsorbing. It then protected the pipe surface by providing a strong and persistent film that acted as a barrier to corrosive fluids. The required dosage to maintain an acceptably low corrosion rate was nearly 20% lower than the dosage required for conventional corrosion inhibitors.

In another case, a midstream gas gathering station operator in New Mexico was experiencing extensive plugging in a gas stream inlet line and filter to the booster, first stage scrubber, and the condensate bullet tanks. Each time the system became plugged, the result was to shut-in production. Prior to the application of the technology, the operator was applying up to 20 gal./week of surfactant at the first stage scrubber and an additional 20 gal./week of surfactant at the bullet tanks. Frequently, the field had to be

shut in to clean the process equipment and change the filters. This resulted in a significant loss of revenue for this operator due to lost production. To combat this problem a trial of the technology was conducted. At the onset of the trial, only 1 gal./d of chemical was applied at the inlet and a ½ gal. of chemical was applied at the bullet tank. In the second stage of the trial, the treatment at the inlet was reduced to a ½ gal./d and the treatment at the bullet tank was discontinued. The treat rate reductions were made because there was no fouling during the first stage. During an 18 month period while the technology was being continuously applied at this location, there were zero shut ins.

An operator in Wyoming was experiencing frequent plugging of injection wells due to the buildup of oily pipeline deposits. These deposits were increasing well downtime and creating additional costs associated with screen cleaning and well maintenance. A two man crew had to perform weekly screen cleanings, which resulted in one hour downtime per well every week. The operator had attempted back-flowing the wells and lateral lines but the results were discouraging. Well downtime and production losses were a growing concern, in addition to under deposit corrosion. Four injection wells were selected as a pilot programme to investigate the results of using Clean n Cor technology. In this case, a company representative recommended technology that included winterised multifunctional cleaning capabilities and as well as best in class corrosion performance. Initially the wells were treated at a rate of between 5 and 20 ppm. The rates were increased every three weeks up to 100 ppm, which was then held for three months. After only three months, injection on all four wells had increased by 282 bpd, which was a 50% increase over previous injection rates. This increased injection resulted in 94 additional bpd of oil production. The weekly screen cleanings were reduced from once per week to once every six weeks, thus saving 344 man-hours and 172 hours of well downtime. And, as a result of the decreased amount of pipeline deposition, the risk of under-deposit corrosion in the system was greatly reduced.

ConclusionAs E&P budgets continue to shrink due to low oil prices, oil and gas producers demand more out of their producing assets than ever. Additionally, since much of today’s operating infrastructure continues to operate beyond original design life, producers will increasingly turn to novel, multifunctional technologies like Clean n Cor to keep their systems clean, corrosion-free, and operating at maximum production levels.

The technology incorporates hands-on technical expertise and in-field monitoring combined with innovative chemical products to provide a comprehensive treatment solution. Since it has the ability to maximise oil production and preserve asset integrity under a wide range of field conditions, this technology has an important role to play during the current very challenging market conditions.

References1. Last 18 months price trend for West Texas Intermediate Crude (USD), from

http://www.nasdaq.com/markets/crude-oil.aspx?timeframe=18m. 2. ‘Barclays: Global E&P budgets to see double-dip in 2016’, Houston, Oil & Gas

Journal, PennWell Corporation, (13 January, 2016). 3. Moon, T., ‘Corrosion Inhibitor and Cleaner, Rolled into One.’ Posted to

www.spe.org, (25 April, 2007).4. Horsup, D., (Nalco Company) SPE-108675-MSSPE Annual

Technical Conference and Exhibition, Anaheim, California, U.S.A. http://dx.doi.org/10.2118/108675-MS, (11 - 14 November, 2007).

5. Horsup, D., Dunstan, I., T., S., & Clint, J. S. NACE-07690 ‘A Break-Through Corrosion Inhibitor Technology For Heavily Fouled Systems’ NACE International, (1 January, 2007).

W ith more than 30% of all oil production coming from offshore fields, and 60% of new fields being discovered offshore, the ocean appears to be a marvellous

El Dorado, ripe for oil discoveries. However, along with this wealth of potential come the challenges of a harsh environment as exploration ventures deeper and deeper offshore.

JEROME CUNY, OPEN OCEAN, FRANCE, HIGHLIGHTS THE USES FOR SOPHISTICATED METOCEAN FORECASTING AND HINDCASTING IN OFFSHORE OIL AND GAS OPERATIONS.

ADVANCING METOCEAN

DATA

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Offshore development presents challenges not only in terms of production and worker security but also in terms of environmental protection.

The need for metocean knowledgeA thorough knowledge of the environmental conditions on site is key. This includes sealife along with physical conditions such as wind, wave and ocean currents. This is where the oceanography comes into play in order to fill in the information about the metocean conditions. Metocean analysis, metocean being the contraction of meteorology and oceanography, covers all of the necessary information for the development of any offshore project.

Metocean analysis is important because the ocean covers 72% of the Earth’s surface and is difficult to monitor because of its vast surface area and its depth of up to 4000 m over most of its surface.

Live monitoring and forecastingStudying the ocean is challenging, not only because of its vastness but also because of its temporal variability. Live monitoring and forecasting of metocean conditions are thus absolutely necessary to manage operations securely.

With the emergence of autonomous gliders, drifting and profiling floats, combined with wind, wave and current measuring buoys, and geostationary satellites, real time knowledge of ocean conditions has greatly improved. And the innovation of in-situ measurements is still very active as floating Lidars are increasingly recognised as measurements of wind profile.

Wind, and wave forecasting can accurately predict conditions for upcoming days, helping to deal with emergency situations associated with squalls or hurricanes for instance. However, plenty of research work still needs to be done to go beyond a week of forecasting. These two fields go hand in hand as waves are generated directly by the wind.

On the other hand, even though ocean current forecasting has shown some real improvement in the past 10 years, it still lacks accuracy outside of regions dominated by tides. This is

still a pressing issue in a region like the Gulf of Mexico where the Loop Current presents a spatial and temporal variability that is difficult to understand and thus difficult to forecast. In 2015 for instance, the Loop Current northern limit remained for a long time period at a higher latitude than ever before for unexplained reasons.

The challenge of ocean current forecasting lies in the three dimensional dynamics of the fluid that cannot be easily monitored over a large area, unlike the atmosphere, which is now fully covered by satellite sensors. Monitoring and building up records of historical conditions is thus essential for improvements to ocean current forecasting.

Historical metocean conditionsHence, before thinking about live monitoring and forecasting, a solid knowledge of historical conditions of metocean data on site is essential.

Focusing on the development phase of any offshore project, average metocean conditions are necessary but extreme conditions are also needed for structure design that will resist the rough offshore conditions, thus ensuring the longevity of the FPSO or platform, and the safety of the people working on it.

In order to learn about historical conditions, in-situ instruments have been the favoured choice, but the instruments are required to be set up at sea and parameters are measured at a single location, only for as long as they are left at sea.

In the North Sea and the Gulf of Mexico, offshore developments have been going on for decades, thus offering quite a large amount of measurements at numerous locations providing valuable long term information. For any new offshore locations outside of these two regions, long in-situ measurements are quite scarce.

Satellite technology can be of great use to complete in-situ measurements. Since the 1970s, several satellites have been launched to measure sea surface temperature. Near surface wind speed has been measured from scatterometer sensors with interesting accuracy since the 1990s. More recently, sea surface salinity has also been measured but with less accuracy than sea surface temperature so far. Since the 1990s and the launch

of the Topex/Poseidon satellite, altimetry sensors collecting sea surface elevation data have been able to provide valuable information about waves.

However, the orbiting satellites only cover a given location after a few days, hence limiting the knowledge about sub-daily temporal variability.

Therefore, even though direct in-situ measurements and remote sensing have greatly improved over recent decades to provide key information about ocean conditions, they still present some limitations when a more detailed knowledge of historical metocean conditions is necessary in more remote locations, including the ‘new frontier’ regions such as Eastern Africa, or South East Asia.

Figure 1. Map of mean ocean current magnitude over the North Sea produced from an ocean current numerical simulation output and visualised with Metocean Analytics.

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Ocean numerical simulationAs rigorous statistical analysis requires as long of a time series as possible to estimate reliable averages and extreme values of metocean conditions, ocean numerical simulations are solutions of great interest to complete the in-situ and remote measurements.

Ocean current or wave numerical simulations are produced using wave or ocean current numerical models.

A numerical model is a computer program that solves the equations of ocean dynamics, like the Navier Stokes equation for ocean currents for instance. These computer programs have been developed by oceanography research centres since the 1970s. These programs have greatly evolved over time, considering more complex and more detailed oceanic phenomena. The setup of an ocean current model goes through several key steps.

The first step requires the definition of a spatial grid over a limited area covering an ocean or a sea. At grid crossings, called ‘nodes’, the numerical model will solve the relevant equations taking in account the water depth, the wind forcing, and the information from surrounding nodes. The resulting solution of the equations provides the ocean current magnitude and direction, for an ocean current model for instance.

As the model solves the equation at each node, a map can be obtained with values of ocean current speed and direction at each node. The different forcings and boundary conditions applied corresponding to a specific date and time, the model provides a view of the ocean currents over the chosen area for a specific date and time. The numerical model then repeats that operation for several dates and times, reproducing the ocean conditions over a chosen time period, which can be as long as forcing and boundary condition information are available, thus producing a ‘hindcast’.

As the equations of ocean dynamics are non linear, numerical modelling programs discount the equations, make approximations, and include different hypotheses to solve them. These different choices necessarily generate additional unrealistic ‘numerical’ variability that makes the model deviate from the real conditions.

Hence, numerical simulations need to be calibrated then validated with in-situ or remote measurements as much as

possible. Numerical models do not replace measurements but are very efficient at covering more spatial and temporal ground, thus giving more confidence in the statistics computation, especially the extreme value computation.

So when looking for metocean data in a new area of exploration, relevant numerical simulation datasets provide the first knowledge of the historical metocean conditions. This information will then be completed and improved with the setting up of in-situ instruments.

The challenge of ‘big data’Ocean numerical solutions are thus a great solution but they also represent a large amount of data, which is difficult to fully analyse efficiently to get the most out of. There are a large number

of in-situ measurements and existing ocean numerical simulation datasets covering the whole ocean but taking advantage of this available information when they represent Terabytes of data is a real challenge. So as oil and gas offshore exploration keeps expanding, numerical simulation will be used more and more to understand offshore conditions. It is then important that tools to access and analyse these large amounts of data become easily accessible to in order to remove one key challenge from the long process of exploration.

The big data management and analysis, ‘big data mining’, implies dealing with large storage, fast data access, fast extraction and analysis.

Open Ocean spent three years working on these issues to optimise big data mining, the time for statistical computation, the statistical methodology robustness and the ergonomics of an interface to make it accessible to experts and non experts.

With this goal in mind, Open Ocean has developed Metocean Analytics combining years of experience in oceanography and metocean analysis for the offshore energy sector, with state of the art web technologies.

Management of big data first requires the organisation of the data in such a way that it can be quickly and efficiently searched. The Netcdf format commonly used for numerical simulation output is a solution of choice because of the associated metadata that allows it to target directly only the required time series for a given longitude and latitude.

In order to compute more than one hundred statistics on wind, wave and ocean current data in just a few minutes, it is also necessary to optimise the statistics computation process. The statistical toolbox code is thus parallelised to be run on several processors at the same time.

By combining a large catalogue of numerical simulation data, with fast computing statistical tools and a report editing tool, Metocean Analytics is a solution designed to take full advantage of all the latest advancements in big data management and mining, removing most of the hassle of finding and analysing metocean data.

Figure 2. Wave numerical simulation spatial grid for the North Sea. The spatial resolution is increased in areas closer to the coast. This wave numerical simulation output is visualised and analysed with the with Metocean Analytics solution.

Low oil prices, shrinking margins (or no margin at all), loss of jobs and perhaps the decline of the industry as a whole – the topic has been hanging around oil and gas professionals like a dark cloud for

two years now. One of the most persistent discussions has been whether this is just ‘the cycle’ or whether there is something structurally different about this downturn. This has been particularly poignant for high-cost offshore regions such as the North Sea, which includes AGR TRACS’ training business.

Most people are concluding the downturn is a little different this time around. Longer, deeper, and with less inevitability that the high-cost arenas will simply return to their previous ways of life.

Hope Which begs the question – what is the future here for the thousands of professionals living and working in higher-cost regions? In the service sector, for most businesses the instinctive desire is to hang in, hope for the local upturn and look further afield for work in the meantime. The preference will be for companies to remain at their home locations, where they already have business and personal infrastructure, but is this really workable in the long term? The hope is yes, but not in the sense that workability is thought of today, and training offers an example.

The notion of working globally from areas such as Aberdeen is certainly less fanciful than it would have been one or two decades ago. Global connectivity allows this in a way which is unlikely to be reversed – even the restrictions of an airport with a runway that is still not quite long enough can be overcome more easily than in the past when face-to-face meeting was the only way to progress business.

What is fanciful is the notion that areas such as Aberdeen can simply export ‘Aberdeen’ to an eagerly waiting world that just wishes to be, well, more like Aberdeen. The idea of ‘internationalising’ is a simple and obvious one – the tougher question is how to do it well when there are plenty of emerging providers in other regions.

The questions to ask are: Ì Why should any emerging region wish to call on AGR TRACS’

Training services? Ì Why pay the premium associated with importing expatriate skills? Ì Why not use local talent, especially if that talent has already been

trained up on university Masters programmes run by expatriates?

Essentially, even if the company believes it has done a good job in the past in its own regions, why should it expect that the world is waiting eagerly to be exposed to its personal technical histories and biases? The expectation almost seems a little arrogant.

Mindful exportThe key would seem to be to avoid simply exporting North Sea expertise but instead package the skills in a more tailored way or offer bespoke products.

In the world of training this is readily apparent. The TRACS Training brand has always worked globally, and the brand distinction is the delivery of tailored courses, rather than off-the-shelf products. These take more time and effort to build and maintain than standard commodity products but they are internationally portable. This is not franchising – the company’s skill pool of tutors is made up of staff or close associates who are mostly UK-based and the IP for the courses are generally shared between tutors and the company. It is instead the export of tailored products and the concept of putting manpower-intensive bespoke tailoring first, in preference to the more traditional (and generally more profitable) option of commoditising and generating volume products.

TAILORING

MARK BENTLEY, AGR TRACS TRAINING, UK, GIVES AN INSIGHT INTO WHAT TO DO WHEN BUSINESS DRIES UP AT HOME.

TRAINING

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Is this not what everyone does? Well, no, not really. It can be argued that truly tailored training products are not the norm, principally because of the additional care, attention and effort involved. Non-tailoring is the norm. An extreme example of non-tailoring was recently described concerning a training organisation who designed a course based around the North Sea environment and exported it wholesale to the Middle East. The fact that the case study material embedded in the course was based on offshore projects did not seem to faze the course deliverers – driven by a belief in consistency (and a wish for highly profitable volume delivery) the lack of relevance of offshore technology for desert countries was neatly overlooked.

The simple tailored alternative to the above is to drop the marine aspects. The more subtle but necessary effort is the complete deconstruction of the course to pick out the generic aspects relevant to the Middle East client group, add in the locally specific content which would not have been in the North Sea version of the course and rebuild the event around the interests of the new group. This all requires effort, and goes far beyond simply ‘cutting out the bits about the North Sea’ and changing the date and location on the first PowerPoint slide (a dangerous business in itself, and scope for much embarrassment if done hastily and carelessly).

AGR believes that effort is necessary to transfer the skills and knowledge of experts in areas like the North Sea to a new region. What to do when the business dries up at home? Export, but with effort; tailor, and tailor mindfully.

A case in pointA current bid for in-country skills development in an emerging region offers a case in point. The principal commodity providers are in the region, and providing a range of standard but useful off-the-shelf training products in nearby countries. This provision, however, is not wholly in line with the wishes of the Oil and Gas Ministry in the country in question. After discussions with the relevant seniors in the Ministry it emerged their prime concern was the loss of talent out of the country, partly associated with out-of-country training itself, which is provided on an individual basis (generally the simplest and most profitable way of delivering commodity products). Talented individuals were given the opportunity to travel for training, which was used as an opportunity to pick up generic skills, network and apply their augmented CVs and their new learnt skills generically, i.e. not at home. An element of this is inevitable, and not necessarily a bad thing, but from the Ministry’s perspective was not the intended use of finite training funds.

The request from the Ministry was therefore to provide in-country training. This request was met by offering a tailored in-country programme – training teams together, using in-country data and adjusting content to fit the specific issues in that region. Retaining talent also requires a career path and attractive remuneration – out of scope for a training provider (and stretching the definition of ‘tailoring’ a little too far) - but this can be gainfully supported by a tailored development programme and this was something that AGR could help with directly.

Providing such a programme on a one-off basis is highly unappealing to a commodity training provider – the time, effort and overall investment of resources are disproportionate compared to the profitability of running a high-volume, repeating, un-tailored programme from a centralised training centre.

However, for a company that is structured around the delivery of tailored training, not anchored to a physically fixed training centre, the opportunity is a good fit. The time and effort involved in deconstructing existing material, re-writing to fit a new data set and researching the historical needs of a region such that new content can be generated is intellectually stimulating. It is also highly rewarding to see the material ‘land’ when delivered in the new location to a new group of people who

are keen to learn as teams alongside their colleagues. Not as profitable as high volume provision perhaps, but good business nevertheless.

In this way, the ethos and skills developed by a group of tutors founded in Aberdeen are readily exportable to a new area. The key is not any individual genius (there are plenty of talented tutors working on commodity provision in training centres); the exportable product is the approach – the tailoring itself.

Life outside the North SeaThe tailoring ethos is applicable generally. It is the company’s belief that exporting skills and experience from anywhere requires this type of approach. The trend seems to be it is easier to simply try to export standard products and activities, and see if that works.

The question for every professional in their respective businesses is therefore to open up the anatomy of skills and products – literally take them apart and consider what is special or useful about each piece. Some things AGR has done and learnt were really for local use only – the North Sea in this region’s case. Other things are of global benefit and therein lies the value. Rather than simply package up the same products and offer them optimistically to ‘interested others’ elsewhere, it is necessary to critically think through and isolate the components which carry value internationally.

The result may be surprising. The value may lie in just part of an existing product but equally may not be a product at all. The value may simply be the thought processes of the people who had the flair to the build the product in the first place.

For sure, the surviving useful products are likely to be different, and ‘different’ can still be based in Aberdeen (or anywhere).

Figure 1. Mark Bentley on a field trip in Patagonia.

Figure 2. TRACS Training tutor and global advisor in early field development, Richard Oxlade, in Jakarta.

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