The semi platform P-56 has been put into operation on the Marlim Sul Field and started production from well 7-MLS-163HPRJS.

Petrobras’ Brazilian natural gas output increased by 8% in July compared with the same month a year ago, up to 56.71 million cu meters/day. With oil, the country averaged 2,325 million bbl/day of oil equivalent in July.

In August, Petrobras said it put the semisubmersible platform P-56 into operation in the Campos Basin’s Marlim Sul Field in the state of Rio de Janeiro. The unit went into production from well 7-MLS-163HPRJS, which can produce up to 16,000 bbl/day.

Installed at a water depth of 1,670 meters, the new platform was designed to process up to 100,000 bbl/day of oil when it reaches full capacity, which is expected in Q1 2012. In addition to heavy oil, P-56 is capable of processing and treating up to 6 million cu meters/day of natural gas.

The platform will be interconnected to 21 wells, 10 of which are oil producers and 11 are water injectors. Oil will be transported by pipeline to platform P-38, an FSO unit (floating oil and gas storage and offloading system) anchored 20 km away from P-56. From the P-38, the oil will be transported on shuttle tankers, and the natural gas will be piped to Cabiúnas terminal.

To prove local manufacturing capability, the P-56 hull was entirely built in Brazil.

WesternGeco begins Dual Coil Shooting survey

WesternGeco recently started the Revolution II multiclient survey in the highly prospective Green Canyon area of the Central Gulf of Mexico. The Revolution II multiclient survey will provide full-azimuth (FAZ) coverage on more than 3,200 sq km or 140 Outer Continental Shelf (OCS) blocks.

Building on multi- and wide-azimuth techniques, Dual Coil Shooting is an advanced method of acquiring full-azimuth, ultra-long offset marine seismic data using four vessels following a circular path. This method allows the fleet to focus imaging on specific areas of client interest.

Dual Coil Shooting provides better target illumination in challenging environments by enabling greater azimuthal coverage and a higher signal-to-noise ratio. WesternGeco will apply advanced seismic data processing techniques to the survey.

Revolution II builds on the FAZ acquisition of Revolution I in the Western Gulf of Mexico acquired in late 2010.

CNPC’s Baoji produces China’s 1st high-strength H-level drilling riser

On 8 August, China National Petroleum Corp (CNPC) subsidiary Baoji Petroleum Steel Pipe Company produced China’s first high-strength H-level marine drilling riser. Test results showed that all the mechanical performance indexes of the riser were in compliance with the rules and standards in DNV OS F101 Submarine Pipeline Systems.

Separately, another manufacturing arm of CNPC, Baoji Oilfield Machinery Co (BOMCO), has signed an agreement with Brazilian companies BRCP and ASPERBRAS to establish an oil equipment joint venture (JV). The JV, signed in Beijing on 16 July, is the first of its kind between a Chinese oil company and Brazilian companies in the oil equipment manufacturing sector. Located in Salvador city in Bahia, Brazil, the JV is expected to become operational in October. BOMCO will have 34% stake while BRCP and ASPERBRAS will each hold 33%.

Liner drilling system saves offshore well

Baker Hughes’ liner drilling system was used to save an offshore well, saving $7.5 million in mud and nonproductive time losses. An operator was unable to drill through a complex micro-fractured formation because tools and drilling fluids were being lost in the hole. After three sidetrack attempts, the operator was considering plugging and abandoning the well. Baker Hughes suggested a liner drilling solution using a TORXS expandable liner hanger packer system with an EZCase casing bit system to drill the section.

The objective was to drill 40 m (131 ft) from 3,230 meters to 3,270 meters (10,597 ft to 10,728 ft) to case and isolate the difficult zone. Baker Hughes drilled the hole, set the liner and the liner top packer in one trip. Due to different pore pressure zones, the customer was also able to drill the next section with water-based mud rather than oil-based mud.

Baker Hughes completes 1st multistage shale fracking in Argentina

Baker Hughes recently completed its first unconventional hydrocarbon shale hydraulic fracturing and stimulation project in Argentina for YPFin the Neuquén basin. The multistage fracturing operation was performed using more than 12,000 hydraulic horsepower and a total fluid volume exceeding 7,000 cu meters.

YPF is evaluating well results to determine the potential for expanding operations. Several operators are developing and executing exploration plans in Argentina’s unconventional hydrocarbon plays.

“While the bulk of unconventional shale activity has been in the US, interest in shale plays in other parts of the world are beginning to expand, and indications are that Argentina will be a promising area for international success,” Rod Larson, president of Latin American operations for Baker Hughes, said. “We are positioning our operations in Latin America to support this new market, and we are leveraging our capabilities and lessons learned in the US to help operators in Argentina.”

Baker Hughes also provided coiled-tubing services for the project.

Field-tested stage multiplier technology allows fracturing up to 60 stages per lateral

The RepeaterPORT sleeve enables fracturing of up to 60 stages per lateral. By using the same-size ball, it multiplies the number of stages that can be fractured.

Packers Plus Energy Services recently released the RepeaterPORT sleeve, which enables fracturing of up to 60 stages per lateral, according to the company. The stage multiplier technology increases the number of stages available in the company’s StackFRAC HD system. By using the same-size ball, the RepeaterPORT sleeve multiplies the number of available stages that can be fractured, allowing for optimization of fracture crews and the use of less frac fluid. There are a variety of ball seat sizes, allowing numerous stages to be run in sequence, the company said.

“We can actually drop the same-size ball multiple times and activate specific ports within the system,” Packers Plus president Dan Themig said.

The RepeaterPORT has been field-tested in the US and is available worldwide.

Apache’s Forties well IP highest in field since 1990

Apache Corp’s Charlie 4-3 development well on the Forties field in the UK sector of the North Sea, completed in June, commenced production at a rate of 12,567 bbl/day of oil. This is the highest initial production (IP) rate on the Forties since 1990 and follows the previously disclosed Charlie 2-2, which was completed in March with an IP rate of 11,876 bbl/day.

Apache acquired a new 4D (time-lapse) seismic survey over Forties in 2010, which enhanced the company’s ability to identify accumulations of bypassed oil. Charlie 4-3 and Delta 3-5, the eighth and ninth development wells brought on production at Forties during 2011, targeted two of these accumulations. Delta 3-5 commenced production at 8,781 bbl/day. Additional 4D driven targets are being identified. Apache expects to drill 16 wells on the Forties field during 2011. When Apache acquired Forties in 2003, the field was producing 40,000 bbl/day. With the onset of these new wells in mid-June, gross daily production rates have reached as high as 70,000 bbl of oil equivalent.

GE Oil and Gas to supply TLP tensioner system to Chevron Big Foot

GE Oil & Gas’ Drilling & Production business has received a contract of approximately $45 million to supply and service the industry’s largest tension leg platform (TLP) marine riser tensioner systems to Chevronfor deployment on its Big Foot field in the deepwater Gulf of Mexico.

GE is making key design modifications to develop “push-up” style marine riser tensioner equipment to enable the Chevron Big Foot TLP to deal with the challenging wave and current movement conditions of deepwater applications. “We are utilizing innovative technology to deliver customized ‘push-up’ style TLP tensioners,” Manuel Terranova, senior VP – global regions and sales, Drilling & Production, GE Oil & Gas, said.

The vertically moored floating TLP is suitable for use in a wide range of water depths; to date, TLPs have been deployed in water depths approaching 5,000 ft. The GE-Chevron Big Foot unit will be the first to operate in depths of 5,200 ft.

The Big Foot TLP will be Chevron’s sixth operated facility in the deepwater Gulf of Mexico. It will include an on-board drilling rig and will have a production capacity of 75,000 bbl/day of oil and 25 million cu ft/day of natural gas. Installation of the TLP is scheduled to begin in November 2012, and first oil is expected in 2014.

Noble Corp has exercised options with Jurong Shipyardfor the construction of two additional high-specification heavy-duty, harsh-environment JU3000N jackups. This brings to six the total number of new jackup rigs the company has under construction with Jurong. Deliveries are expected during Q3 and Q4 2014.

The Friede & Goldman JU3000N design is an enhanced evolution of the JU2000E design, and the rigs will be able to operate in water depths up to 400 ft and drill to 30,000 ft. The rigs will each have a 75-ft cantilever, 2.5 million lbs of hookload capacity, a high-capacity mud circulating system, and a 15,000-psi blowout preventer system.

In addition, Noble has seven ultra-deepwater drillships under construction, three of which are scheduled to be delivered later this year.

Separately, Noble was recently awarded a contract for the Noble Paul Romano semi and received a contract extension for the Noble Max Smith semi, both located in the Gulf of Mexico. In addition, the company was awarded a contract for the Noble George Sauvageau jackup, operating in the Southern sector of the North Sea.

The Noble Paul Romano was awarded a six-well, approximately 180-day contract by Gujarat State Petroleum Corp for operations offshore Egypt. The rig, which has been idle in the US Gulf of Mexico since June 2010, is expected to commence the new contract in October 2011. The contract could be extended for up to four optional wells.

The Noble Max Smith, operating offshore Mexico for PEMEX, has received a five-month extension of its current contract. The extension commenced in August 2011.

The Noble George Sauvageau was awarded a one-year contract by Wintershall for operations in the Southern sector of the North Sea. The rig is now firmly committed through 2012.

Anadarko strikes light oil on Akasa-1 offshore Ghana

Anadarko Petroleum recently made a light oil discovery at the Akasa-1 exploration well on the West Cape Three Points Block offshore the Republic of Ghana. The well encountered 108 net ft of primarily high-quality, oil-bearing pay from four main Turonian-aged sand packages, similar to those found in the Jubilee and Mahogany East areas. Samples indicate oil of approximately 38° API gravity.

The well was drilled to a total depth of approximately 12,850 ft in approximately 3,800 ft of water. The partnership plans to preserve the Akasa-1 for future use and plans further delineation in the area with appraisal activity at both Akasa and Teak.

Union Drilling to add 2 new rigs to fleet for Fayetteville

Union Drilling is purchasing two new drilling rigs based on three-year contracts. The 1,500-hp AC electric drilling rigs, designed for pad drilling and efficient rig moves, are expected to be completed in Q1 2012. They will be deployed to Arkansas for the Fayetteville Shale. Since January 2011, the company has added two 1,000-hp rigs to its fleet, and two more 1,000-hp rigs are expected to be completed for operations in the Marcellus Shale by the end of 2011.

Chikyu to drill offshore Japan for methane hydrate test

Japan Drilling Co and Japan Petroleum Exploration Co have signed a deal for the Chikyu deep-sea vessel to drill three observation wells and a test well offshore western Japan in preparation for a methane hydrate test production program. Drilling will commence in January/February 2012.

Maersk invests in advanced drilling simulator

Maersk Drilling and Maersk Training have invested in a DrillSIM-6000 drilling simulator from UK-based Drilling Systems to be housed in a purpose-built complex in Svendborg, Denmark. The system will be able to simulate various well control scenarios, including Maersk-generated deepwater training, and will enable crews to practice advanced drilling operations, including stuck pipe, jarring, MPD, BOP landing and LMRP disconnects. The simulator will incorporate custom rig packages for three Maersk newbuilds, including the CJ70 jackup, plus an ultra-deepwater semi and an ultra-deepwater drillship. The drilling simulator also will include three generic rig packages. The drilling simulator is expected to be fully operational by mid-2012.

SEMS toolkit available on IADC website

Lessee companies operating on the US outer continental shelf have been required to develop and implement a safety and environmental management systems (SEMS) plan by 15 November 2011. Because contractor companies will play a vital role in helping ensure lessees achieve SEMS compliance, the Offshore Operations Committee’s (OOC) SEMS Task Force, led by Jeff Ostmeyer, Anadarko Petroleum, has developed a collection of tools to help contractor companies prepare for the SEMS implementation. IADC and the Center for Offshore Safety contributed to this work.

The toolkit includes:

• Audit checklist;
• Matrices of regulatory mandated training for drilling/marine/production;
• Knowledge and skills documentation worksheet;
• Operator-contractor agreement letter templates;
• Terms/definitions – clarification document; and
• Compliance readiness worksheet.

These tools present the collective views of professionals in the industry who have reviewed the SEMS rule and identified where the regulation points to the contractor as needing to take specific actions and supply documents or records of those actions to the lessee in support of the lessee’s SEMS plan. The tools can also be used by lessees who do not have SEMS plans in place.

The tools are available here. 

H&P to step up FlexRig construction pace due to demand increase 

Helmerich & Payne in late July announced agreements to build and operate 20 additional FlexRigs, bringing to 58 the total number of new FlexRigs the company has announced commitments to construct during this fiscal year. Including these 20 units, H&P currently has 42 FlexRigs under construction. By October 2011, the company expects to be completing four new units per month, up from the current rate of three new rigs per month, due to a significant increase in demand. 

The 20 new rigs announced in late July will be built under multi-year term contracts with four exploration and production companies and are scheduled to be completed during fiscal 2012. The names of the customers and other terms were not disclosed. 

Pacific Mistral wins 3-year contract from Petrobras

Petrobras has awarded Pacific Drilling’s Pacific Mistral ultra-deepwater drillship a three-year contract for operations in Brazil, expected to commence in Q4 2011. The drillship, delivered by Samsung Heavy Industries in June 2011, is equipped to operate in water depths up to 12,000 ft and drilling wells 37,500 ft deep.

CROSCO’s Zagreb 1 in shipyard for overhaul

CROSCO Integrated Drilling & Well Services’ semisubmersible Zagreb 1 recently entered the shipyard to undergo maintenance and service that includes an overhaul of all drilling equipment, the blowout preventer overhead crane and anchor winches. The program is expected to be completed by October this year.

Additionally, Lloyd’s Register is performing the five-year rig survey on Zagreb 1. “Upon completion, Zagreb 1 will be fully certified and refurbished,” CROSCO president Igor Vrban said.

The upgrade work involves NDT class inspection of the hull and class inspection of the anchor winches and wires, as well as the ballast tanks and anchors. New high-pressure mud, cement, choke and kill lines will be installed.

BOEMRE to hold 1st lease sale since Macondo

The US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) will hold the first oil and natural gas lease sale in the Gulf of Mexico since Macondo, Western GOM Lease Sale 218, in New Orleans on 14 December. It will include all available unleased areas in the Western Gulf Planning Areas offshore Texas, encompassing about 3,900 unleased blocks covering approximately 20.6 million acres. It’s estimated the sale could result in the production of 222 million to 423 million bbl of oil and 1.49 trillion to 2.65 trillion cu ft of natural gas.

Ocean Rig Poseidon heading to Tanzania for Petrobras

Ocean Rig took delivery of the Ocean Rig Poseidon on 28 July. The next day the ship began mobilization to Tanzania, where it will drill for Petrobras International. The naming ceremony for the Ocean Rig Poseidon and Ocean Rig Mykonos took place at the Samsung Heavy Industries shipyard in South Korea on 8 July.

Ensign Energy Services has agreed to acquire the land drilling division of Rowan Companies, which includes 30 electric land drilling rigs, all equipped with top drives. Ensign expects the acquisition to boost its presence in the southern United States, complementing existing US operations in the Rocky Mountain region and California.

More than half of Rowan’s land drilling rigs were constructed in the last five years, and many of them are equipped with automated pipe-handling capabilities. Upon completion of the transaction, Ensign’s global drilling rig fleet will increase to 340 marketed drilling rigs, with 115 drilling rigs located in the United States.

Bonno, Monroe awarded promotions at Transocean

Transocean has promoted Terry Bonno to senior vice president, marketing, and Mark Monroe to vice president, account management.

Ms Bonno previously served as vice president marketing and has approximately 30 years of industry experience, including 17 years with Global Marine and Applied Drilling Technology.

Based in Houston, Mr Monroe will be responsible for overseeing the company’s relationships with key US-based customers. Previously serving as managing director, marketing, he joined Global Marine in 1983 and held numerous marketing positions with Global Marine and GlobalSantaFe. In 2000, he was promoted to VP sales and contracts, with responsibility for the sales, contracts and marketing of the GlobalSantaFe fleet in North and South America, Southeast Asia and West Africa.

Angelo Pinheiro

Pinheiro receives SPE regional HSE award

Angelo Pinheiro, project HES manager – upstream developments for Marathon Oil Corp, was awarded the 2011 SPE Regional Health, Safety, Security and Social Responsibility Award on 17 May at the SPE Gulf Coast Section annual awards banquet in Houston. Mr Pinheiro has more than 20 years of experience as a safety and environmental professional in oil and gas E&P. He earned his Bachelor of Technology degree at Canada’s Memorial University and M.S. in technology management at Texas A&M University-Commerce, and is pursuing a doctorate in emergency management at Oklahoma State University.

Keppel names Tong senior executive director of board

Tong Chong Heong, Keppel Offshore & Marine CEO, has been appointed senior executive director of Keppel Corp. He has served as executive director on the Keppel Board since 1 August 2009, after succeeding Choo Chiau Beng as CEO of Keppel O&M on 1 January 2009.

FMC, Shell sign equipment deal for Australia’s Prelude

FMC Technologies has signed an agreement with Shell Development to supply subsea production and associated topside systems for the Prelude field development. FMC also will perform installation and commissioning services. The Prelude field is located in the Browse Basin of Western Australia, in water depths of approximately 820 ft (250 meters). It will become Shell’s first field development to use a floating liquefied natural gas facility. FMC’s scope of supply includes seven large-bore subsea production trees, production manifolds, riser bases, subsea control systems and other related equipment.

Kerry Girlinghouse

Girlinghouse appointed VP well control engineering

Wild Well Control has named Kerry Girlinghouse vice president of well control engineering. Mr Girlinghouse has been with the company since 2004, most recently as a senior technical adviser within the engineering division. Based in Houston, he will lead the engineering division, increasing his role in global well control and prevention and response services.

Herring is Lee C Moore’s VP production/procurement

Melissa Herring has joined Lee C Moore, a Woolslayer company, as vice president – production and procurement. She previously served in procurement management roles and on the executive teams for Atwood Oceanics, Premier Drilling and Parker Drilling.

Heintzelman to succeed Santiago at GE Oil & Gas

Dan Heintzelman, CEO of GE Energy Services, has been named CEO of GE Oil & Gas. He will succeed Claudi Santiago, who has served as CEO of GE Oil & Gas for the last 12 years and is retiring in December. Steve Bolze, CEO of GE Power & Water, will now lead an expanded portfolio with the addition of Power Generation Services, formerly part of Energy Services, to the Power & Water business. Dan Janki, currently GE Energy’s chief financial officer, has been named CEO of GE Energy Management, a newly formed business within Energy. This business will consist of technology solutions for the delivery, management, conversion and optimization of electrical power for customers across multiple energy-intensive industries.

WCS awarded IACET Authorized Provider status

The International Association for Continuing Education and Training (IACET) has awarded Well Control School (WCS) with Authorized Provider status. IACET Authorized Providers are the only organizations approved to offer IACET Continuing Education Units. The recognition period lasts for five years and includes all programs offered or created during that time. “Our new partnership with IACET is a demonstration of our commitment to lifelong learning and high standards for all of our programs,” WCS president Ed Geissler said.

Peyton named Superior’s VP corporate HSE

Superior Energy Services has named Kerric Peyton VP of corporate health, safety & environmental. He will lead the execution of all technical, functional, auditing, compliance and training responsibilities related to the HSE function across the organization. Mr Peyton was previously a drilling superintendent and manager of worldwide HSE activities at an offshore drilling contractor. He holds a bachelor’s degree in human resource management from New School University and has completed post-graduate work in business administration from Regis University.

PRODUCTS

Vertical proppant storage system reduces pad size

Halliburton has introduced the SandCastle PS-2500 proppant silo. The unit offers a reduced footprint with no volume compromise compared with traditional horizontal proppant storage units. Space is saved by orienting the unit vertically once on location. The unit also is able to transition itself from the horizontal position to the operating (vertical) position under its own power provided through a solar power system housed within the PS-2500 silo.

The unit requires no external power source to operate. This capability eliminates the diesel engine normally required for each conventional proppant handling/storage container. The SandCastle PS-2500 unit has a total working volume of 2,500 sacks (250,000 lbs), divided into two separate bins. Proppant can be discharged from either bin at a rate of more than 200 sacks/min.

High-temperature ESP system targets wells up to 250°C

Schlumberger has released its third-generation REDA HotlineSA3 high-temperature electric submersible pump (ESP) system for steam-assisted recovery operations and geothermal applications. This latest release can reliably produce from wells with bottomhole temperatures of up to 250°C, enabling the installation of the ESP at the earliest stages of the development of the steam-assisted gravity drainage (SAGD) chamber.

The HotlineSA3 system incorporates an integrated design that extends the ESP operating envelope and run life. Integrated surveillance and control through reliable fluid pressure, temperature and internal motor temperature measurements help reduce sub-cool and steam oil ratio.

The system, which has passed extensive testing at max-rated temperatures, includes a multifunction integrated motor unit, thermally compensated pumps, downhole monitoring gauges for pressure and temperature, power cables and a surface controller.

End caps with the Hercules Lugless 150H BOP Cap can be secured using a wrench rather than a hammer.

Lugless BOP cap can be secured with wrench

R&M Energy Systems is offering the Hercules Lugless 150H BOP Cap, which allows operations to use a wrench rather than a hammer to secure the end caps. It can be operated with a standard 24-in. or 36-in. pipe wrench, a 36-in. adjustable wrench or a 3-in. wrench; no hammer is required. It can be installed on all older 150H BOP models that currently have wing caps.

New flexible riser monitoring system achieves full success rate in testing

A flexible riser integrity monitoring system has achieved a 100% success rate in a dynamic test process, according to Pulse Structural Monitoring. FlexASSURE uses non-invasive sensors to detect breaks in the tensile armor wires of a flexible riser, building a detailed picture of structural integrity and alerting the user to early signs of deterioration.

The technology was conceived as a reliable means of validating riser integrity in deepwater installations.

The system, comprising monitoring hardware, a real-time data acquisition system and data-processing interface, was developed, tested and qualified in Brazil, where flexible risers are responsible for transporting approximately 80% of offshore production amid increasingly challenging conditions.

FlexASSURE can be installed on a new riser to provide integrity assurance through its lifetime or retrofitted to an existing riser where there may be concerns over its remaining life.

The system was qualified over three years, undergoing laboratory and offshore testing before progressing to a full-scale dynamic test in which it was attached to a riser and subjected to loads representing 100% service life, accounting for a 10-time safety factor. This activity was monitored in a blind test, in which FlexASSURE detected 100% of the wire breaks, with no false alarms.

Industry groups such as OPITO, OMHEC and NCCCO have been working to enhance competency standards and provide an exam program for lifting and hoisting tasks and personnel, and most are available online.

The International Association of Oil and Gas Producers (OGP) Lifting and Hoisting Task Force has been reviewing developments in defining competencies for personnel involved in lifting and hoisting tasks. There are numerous bodies around the world who have an interest in this topic, and many have been proactive in trying to better define competencies during the past few years.

In the majority of incident and accident investigations involving lifting and hoisting tasks, the training and competence issues invariably top the list of root causes of the event. As a result, companies, trade associations, regulators, classification societies and training organizations have all been striving to better define the training requirements and core competencies that are required for the different tasks performed by personnel involved in lifting and hoisting operations.

Valuable works have been carried out in this field and are available online.

One organization that recently produced a draft of new and revised competency standards for lifting and hoisting is the Offshore Petroleum Industry Training Organisation (OPITO). Although based in the UK, this organization has a growing number of international collaborations. Some of its standards are available online in Russian, ortuguese, Spanish, Bahasa and Arabic.

OPITO recently published standards for the following lifting and hoisting roles:

• Rigger training (stages 1 and 2);

• Banksman and slinging training (stages 1 and 2).

In addition, they defined the following competence standards:

• Rigger competence (stages 3 and 4);

• Banksman and slinging competence (stages 3 and 4).

OPITO defines the four stages as:

• Stage 1 – The initial training program;

• Stage 2 – Supervised workplace experience. The delegate must complete a log book record of the supervised tasks;

• Stage 3 – The formal assessment of the candidate. Successful candidates will be awarded a certificate of competence that is valid for two years; and

• Stage 4 – Re-assessment of competence. Successful recertification will extend the certificate of competence for two years.

OPITO also recently revised their Lifting Operations and Lifting Equipment Regulations (LOLER) Competent Person Competence Standard. The LOLER standard is specific to the UK. The competence standard defines the requirements for a person involved in supervising and managing a lifting operation, and it may be of interest to contractors and companies even if the specific legislation does not apply to the country in which they operate.

All standards referenced above are available on the OPITO website.

The Offshore Mechanical Handling Equipment Committee (OMHEC) also recently produced competency and skills requirements for lifting and hoisting personnel. Made up of representatives from Denmark, Norway, UK and the Netherlands, this organization has developed and published the Competence and Skills Requirements for an Enterprise of Competence of Offshore Cranes. This standard reviews the competencies associated not only with the safe operation of an offshore crane but also with safety issues relating to design, construction, maintenance, inspection, certification and verification of offshore cranes.

The OMHEC Standard is available online.

In the US, the National Commission for the Certification of Crane Operators (NCCCO) has developed a comprehensive practical examination program for the mobile crane operator, tower crane operator, overhead crane operator, signalperson, rigger and articulating crane operator. The comprehensive nature of the practical examination demands an equally comprehensive training and competence program to ensure that candidates complete and pass the examination.

Further information on training courses, examinations and certifications are available on the NCCCO website.

Graeme Lawrie is HSSE manager for OMV.

Dr Lee Hunt, IADC President

Following a devastating forest fire, new growth rises from the charred remains. This is the cycle in nature. In human endeavors, we too must try to rebound from disasters of our own making. In this case, new growth for our industry will come only from nurturing the lessons learned from Macondo.

Among those lessons is what can be accomplished when everyone is committed to a better result. In the case of Macondo, while the tragedy and the loss of life will never be forgotten, we must remember the near-heroic efforts of all those who came together to contain the rupturing well, capture the flow of oil and clean up the affected coast. This was achieved in the first months after the incident when experts from the energy industry were joined by experts from academia, government and regulators, NGOs and environmental groups.

More than 18 months after this tragic event, the opportunity exists for all stakeholders to continue to grow that relationship into a collaborative enterprise in a non-crisis situation. Working together, we can build a better industry with greater responsibility.

For IADC, one sign of that continuing relationship is how stakeholders came together in May this year in a focused effort to address the issues of environmentally improved drilling. Experts from a wide range of backgrounds – Rice University, the Environmental Defense Fund Cuba Program, the Harte Research Institute for Gulf of Mexico Studies, Florida International University, the James A Baker III Institute for Public Policy, the Gulf of Mexico Foundation, the World Ocean Council, Deep Tek and the Trinidad & Tobago Ministry of Energy and Energy Affairs – all participated with IADC to establish a dialogue for improvements that will lead us into a new world of deepwater drilling.

Let’s put the lessons of Macondo in our daily operating manual.

By IPIECA Reporting Task Force; Paul Krishna, ExxonMobil; Bertrand Janus, Total; Olga Gorban, Shell; and Helen Murphy, IPIECA

Figure 1: The “Oil and Gas Industry Guidance on Voluntary Sustainability Reporting” breaks the accounting process into six steps and encourages reporting based on a materiality process and stakeholder expectations. The guidance can be used by any company specifically involved in drilling, well servicing, oilfield manufacturing or other rig-site services.

Oil and gas companies have been among the pioneers of sustainability reporting and have provided leading examples of good reporting practices since the mid-1990s. In this tradition, IPIECA, API and the International Association of Oil and Gas Producers (OGP) have issued the second edition of Oil and Gas Industry Guidance on Voluntary Sustainability Reporting.

Member companies of these organizations recognize that managing sustainability impacts associated with producing fuels and other energy products is an important responsibility. This includes addressing challenges associated with climate change and operating in remote and sensitive areas of the world. The groups also support the industry in addressing these and other sustainability challenges and promote continuous performance improvement on environmental, health and safety, and social and economic topics by developing and sharing good industry practices.

An important practice is sustainability reporting. Clear and consistent reporting helps companies create a solid platform for productive engagement and performance improvement.

Reporting development

An IPIECA Reporting Task Force (RTF), consisting of more than 75 individuals from 20 IPIECA member companies and five trade associations, undertook the task of updating the reporting guidance from 2007 to 2010. The guidance was developed to share good practice across the industry and to encourage companies to keep stakeholders informed about their performance. The guidance was also meant to be the first reference for the companies that do not currently report on their performance but were considering establishing this practice.

The RTF identified important and practical ways to measure sustainability performance in the oil and gas industry. The technical indicators remain central to the revised guidance. The second edition reflects feedback and improvements in reporting practices from many sources within and outside the industry.

A fundamental part of the revision process was the involvement of an external stakeholder panel that advised on both the process and content of the guidance. The panel consisted of leading experts in sustainability reporting practices and represented views of typical report reader groups: business and industry, environmental and community-oriented NGOs, investors and multilateral institutions.

At the onset of the engagement, the panel was asked to assess the quality, credibility and effectiveness of the revision process and to provide ideas for improvement; candid, significant and challenging input was received. A joint statement from the stakeholder panel is included in the guidance.

Why report?

Reporting can bring companies recognizable business benefits. Through communication on its most important sustainability issues, a company’s report becomes a reliable source of information for its stakeholders. By transparently describing its biggest challenges, reporting underpins stakeholder engagement and represents the company’s values in action.

For oil and gas companies, reporting provides a robust platform for describing how strategic issues are being addressed through long-term plans and current initiatives. For example, the report can explain how the company is managing the social and economic impacts or HSE risks of operating in different locations. Once published, this information enables further engagement with stakeholders.

In the longer term, the benefits can provide:

• Enhanced business value as investor confidence grows in response to evidence that the company is managing important risks and positioning itself to take advantage of emerging opportunities;

• Improved operations as employees develop a deeper understanding of a company’s sustainability values, and performance indicators provide insight to support continuous improvement;

• Strengthened relationships as local community leaders, civil society representatives, government officials and regulators, and other key stakeholders learn how the company responsibly manages sustainability issues;

• Enhanced trust and credibility as customers, suppliers and the wider society understand the company’s brand, operations and products; and

• An opportunity for benchmarking among various companies in the oil and gas industry that could potentially affect the choice for partnership during tendering and contractual negotiations.

How to report?

The guidance acknowledges that the industry includes differing types and sizes of multinational and national companies, as well as companies specifically involved in drilling or production, well servicing, oilfield manufacturing or other rig-site services. Most of these companies face specific social and environmental challenges in different locations across the globe, and the guidance recognizes that certain sustainability issues will be more important to some companies than to others.

The guidance places more emphasis in this revision on reporting as an engagement process and encourages companies to determine which issues are most important to their own stakeholders. A range of issues are covered by the indicators, which allows companies a choice on the depth and detail to be communicated. A significant front section on how to report has been included to assist those companies reporting for the first time.

By providing flexibility and consistency, the guidance aims to serve both new and experienced reporters while avoiding the pitfalls of formulaic reporting. To support companies in communicating the issues of most interest to their stakeholders, the second edition contains:

• A six-step reporting process, including a “materiality” step to determine the most important issues for reporting;

• A set of issues and indicators likely to be relevant for reporting by companies within the oil and gas industry; and

• Three levels of reporting elements within each indicator to provide options that enable consistent reporting across the industry: common reporting elements that are well established; supplemental reporting elements that enable greater depth of reporting; and other reporting elements that are less established but emerging.

Reporting process

The guidance is voluntary and does not set minimum requirements or predetermine stakeholder needs. Instead it encourages a consistent “how-to” approach, with companies determining what to report based on a materiality process and stakeholder expectations.

The guidance aims to assist oil and gas companies in developing and enhancing the quality and consistency of their sustainability reports. It is designed for use by any oil and gas company, as well as by companies specifically involved in drilling, well servicing, oilfield manufacturing, or other rig-site services.

The guidance covers the entire spectrum of oil and gas operations, from upstream exploration and production, through downstream refining, transportation and marketing, and also petrochemicals, regardless if a company operates nationally, regionally or internationally.

Promoting sustainability reporting

Many individual oil and gas companies can be commended for the advances that have been made in sustainability reporting within the industry over the past few years. However, the trade-offs that society faces in coming years with regard to the quality of the environment, economic development, standards of living and social justice look to be ever more complex and challenging, as will be societal views on the role played and contributions made by the oil and gas industry.

Sustainability reporting and related stakeholder engagement provide an important forum for individual companies to explore their understanding of the pressing debates, needs for performance improvements on material issues, and plans for meeting future global energy demands in a responsible manner.

It is the goal of IPIECA, API and OGP that the guidance will support the momentum we see within our industry to publish sustainability reports and help reporting companies across the global oil and gas industry to improve the quality and consistency of their reports. The guidance will also provide interested stakeholders with a useful overview of reporting as an industry good practice.

In the first six months of publication, the guidance has received significant industry, external stakeholder,and sustainability media attention, as well as endorsements from industry associations, including the Regional Association of Oil and Gas Companies in Latin America and the Caribbean, the Canadian Petroleum Products Institute and the South African Petroleum Industry Association.

Information about the guidance has been accessed more than 5,000 times online. The document itself has been downloaded more than 2,000 times, and it is increasingly being cited as the reporting basis in oil and gas company sustainability reports and websites.

More information on sustainability reporting within the oil and gas industry is available on IPIECA’s website.

This article is based on a presentation at the IADC Drilling HSE Europe 2011 Conference & Exhibition, 28-29 September, Amsterdam.

By Angelo Pinheiro, Marathon Oil Corp, and Ben D. Cranor, Texas A&M University – Commerce

Figure 1: An automated catwalk eliminates workers’ risk of moving pipe between the catwalk and the rig floor. Courtesy of Canrig Drilling Technology

Musculoskeletal disorders (MSDs) are a significant source of economic loss to drilling companies. It is difficult to pinpoint the extent of MSDs in the industry as: a) there are few published studies, b) MSD injuries and illnesses are not separately accounted for in accident statistics and c) the cost of related injuries, illnesses and work disruptions is not clearly known. However, MSDs have been and continue to be an occupational risk factor, as illustrated by these studies:

• 47% of injuries in the Norwegian offshore petroleum sector were related to MSDs. Of those, 20% were back injuries, 53% were upper limb disorders and 16% were lower limb disorders.

• The National Academy of Sciences estimates MSDs cost between $45 billion and $54 billion in 1999. The costs would be significantly higher today.

• Recent field research indicates ergonomic issues that lead to MSDs are abundant in the oil and gas industry.

These statistics indicate that MSDs are a source of significant economic loss and highlight the need for more formal management. This article describes and discusses the components of a basic ergonomics program for an oil and gas drilling operation.

Ergonomic program design

Table 1: Engineering controls can be used to virtually eliminate or reduce ergonomic hazards encountered on an offshore rig.

A ergonomics program should not be a standalone effort but should be managed within the Occupational Health and Safety Management System (OHSMS). Drilling and service contractors are advised to use this information with caution and to consider hiring a certified ergonomist. An article in the March/April 2001 issue of Drilling Contractor (p22) provides guidance on selecting an ergonomics consultant.

An ergonomics program should include:

• Management leadership and employee participation;

• Hazard information and reporting;

• Job hazard analysis and control;

• Training;

• MSD management; and

• Program evaluation.

Management leadership and employee participation

Figure 2: Automated tools, such as an automated floor wrench, remove workers from performing high MSD-risk tasks. Courtesy of Canrig Drilling Technology

Participatory ergonomics, where management and employees cooperate to reduce the incidence of MSDs, has been growing. Management commitment and leadership can be demonstrated by:

• Formulating and championing polices aimed at MSD prevention;

• Sanctioning human and financial resources required for ergonomic program implementation;

• Establishing objectives, goals and metrics for the program;

• Defining roles and responsibilities, and holding leaders accountable for program implementation;

• Making STOP WORK an employee responsibility when situations could cause/exacerbate an MSD;

• Including ergonomics in rig design and specifications, “Management of Change” reviews and safety inspections;

• Establishing an ergonomics program committee and meeting with employees to discuss the issues and solutions; and

• Requiring periodic program reviews/audits and ensuring corrective actions.

Opportunities for employee participation in the ergonomic program include:

• Active involvement in the ergonomics program committee;

• Participation in the development of policy, processes and procedures;

• Involvement in ergonomic hazard identification and risk assessments;

• Participation in ergonomic surveys and workplace inspections and tests;

• Evaluation and selection of personal protective equipment (PPE); and

• Participation in MSD incident investigation.

Hazard information and reporting

Figure 3: During drilling operations, the top drive ergonomically reduces the number of manual connections needed. Courtesy of National Oilwell Varco

Ergonomic hazard assessment involves gathering and assessing data for MSD. Such information may be provided by:

• Injury and workers compensation reports and treatment logs (written consent from the employee must be obtained);

• MSD symptom surveys and previous ergonomic studies;

• Employee reports of ergonomic hazards, such as repetitive and/or forceful lifting and handling, cramped working conditions requiring awkward postures, back bending, high arm forces, vibration, contact stress, fatigue due to prolonged standing or sitting, etc;

• Jobs identified during risk assessments that have the potential for strains, fatigue, pain and discomfort because of physical workloads and repetitive tasks. Those jobs are also the most frequently reported cause of employee complaints in the offshore petroleum industry;

• Modification requests (to rig layout, systems, processes, equipment, etc) that could impose or increase the MSD risks;

• Well drilling and well service programs, where inadequate consideration to schedules could impose MSD risks;

• Purchase and maintenance records for hand and power tools (e.g., pipe wrenches and pipe tongs) that point to frequent replacement or service requests;

• Industry newsletters, safety alerts and studies, and information published by agencies and associations, such as the Human Factors and Ergonomics Society and the Association of Canadian Ergonomists;

• Employee job descriptions. The majority of drilling jobs involve MSD risks. Three such positions that can be singled out are the floorhand, derrickhand and roustabout. Those positions involve repeated lifting, lowering, pushing, pulling, carrying and a high degree of attention for prolonged periods. These jobs must often be performed under harsh conditions, which can increase the risk of injury or aggravate an existing condition.

Job hazard analysis and control

Figure 4: A sack-handling unit elevates sacks to the most ergonomic height. The operator slides the sack onto the roller table and pushes it into the machine, which automatically starts and performs the slitting, emptying and feeding sequence, including packing the emptied sack into the waste bag. Courtesy of National Oilwell Varco

After information has been compiled on the ergonomic hazards, a job hazard analysis should be performed to assess the risks, qualitatively and quantitatively. Several methods are available for ergonomic hazard assessment, including:

• Washington State, Appendix B Criteria for Analyzing and Reducing MSD Hazards. This technique is suitable to analyze jobs that involve awkward postures; high hand force; highly repetitive motion; repeated impact; heavy, frequent or awkward lifting; and hand-arm vibration.

• ACGIH Hand-Arm Segmental Vibration (HAV). The procedure for measuring HAV is provided in the ACGIH TLV and BEI booklet, along with guidance on the desirable exposure levels.

• Snook Tables are based on the psychophysical methodology, which combines heart rate, oxygen consumption and anthropometric (body dimensions) measurements with feelings of exertion or fatigue to estimate the male and female population that can safely carry out jobs involving lifting, lowering, pushing, pulling and/or carrying. Published by Liberty Mutual (Manual Material Handling Guidelines), these tables are useful for drilling ergonomic hazard assessments.

• The revised NIOSH Lifting Equation combines biomechanical, physiological and psychophysical criteria to determine the recommended weight load (RWL) for jobs involving two-handed manual lifting. It starts with a load constant of 51 lbs (23 kg), which is adjusted downward by reach, distance, asymmetry, frequency and coupling multipliers to determine the RWL. The lifting index is then determined to understand the magnitude of physical stress for the job. This method cannot be used for:

o Lifting/lowering with one hand;

o Lifting/lowering for more than 8 hrs;

o Lifting/lowering while seated or kneeling;

o Lifting/lowering in a restricted work space;

o Lifting/lowering unstable objects;

o Lifting/lowering while carrying, pushing or pulling;

o Lifting/lowering with wheelbarrows or shovels;

o Lifting/lowering with high-speed motion (faster than about 30 in./sec);

o Lifting/lowering with unreasonable foot/floor coupling (less than 0.4 coefficient of friction between the sole and the floor);

o Lifting/lowering in an unfavorable environment (i.e., temperature outside the 66-79°F range and relative humidity outside the 35% to 50% range).

• Posture, Activity, Tools and Handling (PATH). The PATH method is suitable for jobs that are non-repetitive and non-cyclic (or have irregular cycles). PATH takes into account work postures, worker activity, tool use, loads handled and grasp type.

Job hazard analyses should be performed by specialists who are trained in ergonomic evaluations since it involves operations analysis, time studies, occurrence sampling, measurements (of the workstation, tools, working environment, body dimensions, physiology, etc), employee interviews, work observations and documentation reviews.

Ergonomic hazard control methods

Figure 5: Automated power slips eliminate repetitive handling of pipe slips. Manual slips weigh up to 250 lbs and impose biomechanical and physiological stresses. Courtesy of National Oilwell Varco

The selection of controls for MSD should follow the three-tier hierarchy recommended by OSHA: engineering controls, administrative controls and PPE.

Engineering controls

Engineering controls are based on the principle of designing the hazard out of the job (elimination), and when that cannot be achieved, enclosing the hazard, substituting it with safer alternatives, or modifying the equipment or working arrangements. Examples where engineering controls can be used to reduce ergonomic hazards on a drilling rig are shown in Table 1.

Technological advances have made possible the automation of high MSD-risk tasks such as making and breaking pipe joints and moving pipe from the catwalk to the rig floor and vice versa. Some of these are illustrated in Figures 1 to 5.

Administrative controls

Administrative-type controls should be used in combination with engineering controls. Examples of administrative controls for drilling rig applications are:

• Work procedures and job safety analyses that address MSD hazards and risks;

• Training employees to recognize MSD risk factors and their prevention and treatment;

• Job rotation of personnel in jobs with high physical demands to less stressful jobs;

• Housekeeping to ensure that walking and working surfaces are clean and free of clutter, oil/grease, water, etc. This will ensure good traction for lifting tasks;

• Planned maintenance system for equipment, tools, floor surfaces, etc; and

• Purchasing controls that specify ergonomic standards in purchase and work orders.

Personal protective equipment controls

PPE is the last line of defense, as a malfunction would immediately expose the employee to the hazard. PPE should be used only to augment engineering and administrative controls. They should be comfortable to wear, provide the desired protection and not add to the hazard. PPE should be designed, inspected and maintained to the required standard, manufacturer recommendations and regulatory requirements. PPE aspects with respect to MSD prevention include:

• Work boots with ankle protection;

• Anti-vibration gloves for use with impact and pneumatic tools (needle guns, impact wrenches, sledge hammers, etc);

• Gloves that provide the required protection, dexterity and grip;

• Insulated PPE and boot drying racks for work in cold and wet environments;

• Back belts offer no real protection and do not change the employee’s perception of the physical demands of the task; hence their use is not encouraged;

• Boot scrapers to ensure that the soles are clear of debris, oil, etc.

Training

The successful implementation of an ergonomics program calls for the participation of personnel. Each staff level has specific roles and responsibilities under the program, and they should be trained to carry out those responsibilities. NIOSH (1997) recommends a three-level training program for ergonomics that includes:

• Ergonomics awareness training;

• Training in job analyses and control measures; and

• Training in problem solving.

Ergonomics awareness training

Ergonomics awareness training should be provided to all employees and may include these topics:

• Recognizing and controlling MSD risk factors;

• Signs and symptoms of MSD onset;

• Procedures to report an issue;

• Company ergonomics program;

• Roles and responsibilities under the program;

• Measures the company has taken to reduce MSD; and

• Regulatory requirements.

Training in job hazard analyses and control

Training in job hazard analysis and control is required for employees involved in the development of job safety analysis and standard operating procedures, review of modification/change requests, health and safety committee, and those involved in recommending or implementing the recommendations from job hazard analyses. The following topics are typically addressed:

• MSD risk assessment methodologies and criteria;

• Hierarchy of controls; and

• Corrective action tracking system.

Training in problem solving

Training in ergonomics problem solving is the highest level of training and requires completion of awareness training. Job hazards and control training are pre-requisites. Training is intended for personnel involved in resolving MSD risk factors and should be provided by a certified ergonomist. Training should include:

• Hazard identification methods commonly used in the industry;

• Qualitative and quantitative risk assessment methodologies;

• Cost-benefit analysis;

• A review of the technologies available for MSD reduction;

• Team-building, consensus development and problem-solving techniques;

• Risk communication.

MSD management

MSD management addresses prevention and treatment. Prevention pertains to identifying and controlling risk factors through the use of hazard assessment techniques and engineering, administrative and PPE controls. The treatment aspects pertain to post-injury medical treatment, rehabilitation and reintegration into the work force. Those responsibilities fall on management, employees and healthcare providers (HCPs).

Employer responsibilities

Management is further responsible for familiarizing the HCP with workplace hazards, sanctioning workplace modifications and making reasonable accommodations for employees returning to work with functional limitations.

Employee responsibilities

Employees who have been diagnosed with MSD are further responsible for following the HCP’s advice with respect to medical treatment, physiotherapy, counseling and functional restrictions.

Healthcare provider responsibilities

An HCP should be appointed for the diagnosis and treatment of MSDs. The HCP must understand the physiological, psychological and environmental parameters and constraints that pertain to the employee’s work. HCP responsibilities include:

• Familiarizing with company policies, systems and processes, and the work activities and conditions under which they are performed;

• Advising and guiding the medic on treatment and care of MSDs;

• Participating in ergonomic hazard evaluations; and

• For “at-risk” employees: a) reviewing their medical histories, b) assessing MSD factors, c) conducting initial, annual and post-injury assessments, d) providing a written opinion of the employee’s medical condition with respect to the job activities, risk factors and MSD factors, e) recommending time off work or work restrictions, f) specifying the functional capacity limitations and recommendations for workplace or work modification, and g) informing the employee of the results of the medical assessment;

• Liaison with the worker’s compensation insurance provider, injured employee’s personal physician and agency officials (if required); and

• Maintaining the confidentiality and privacy of information and records.

Early reporting and access to healthcare providers

Provisions should be made to enable the early reporting of MSD symptoms to the HCP so that case management can promptly begin. Early diagnosis and treatment of MSD symptoms has been proven to reduce the severity of the condition.

Program evaluation

An evaluation of the ergonomics program should be performed at least annually. The evaluation should be performed by an individual who is familiar with the program but not directly involved in its development or implementation. The program evaluation should:

• Verify that requirements have been implemented;

• Evaluate the effectiveness of controls following interventions to correct MSD hazards;

• Comment on the metrics and actual performance results;

• Evaluate the ergonomics awareness of employees, their understanding of reporting mechanisms and their satisfaction with the actions taken to correct hazards; and

• Recommend specific control measures to correct any identified gaps.

Conclusion

MSDs impose major operating costs on employers in the drilling industry. An ergonomics program that is a subset of the occupational health and safety management system would provide a vehicle to anticipate, recognize, evaluate and control MSD risks.

Angelo Pinheiro is project HES advisor – upstream developments for Marathon Oil Corp, and Dr Ben Cranor is assistant professor at the Department of Engineering & Technology at Texas A&M University – Commerce.

Authors’ note: The recommendations and ideas expressed in this article are those of the authors and do not necessarily represent the views of Marathon Oil Company, its directors, parent company, affiliates, subsidiaries, executives, shareholders or employees.

References

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IADC (2011). Incident statistics program: 2022 Reporting guidelines. IADC.

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By Brian Grayson, Weatherford International

Closed-loop drilling systems are scalable to the task and can help minimize risk to personnel and the environment. Additionally, kicks and losses become more readily and accurately diagnosed in closed-loop systems.

Although securing safe working conditions and creating efficient operating processes may imply laborious efforts and cumbersome equipment, Weatherford International’s approach leverages a fundamental aspect of all drilling operations – the mud system. Fluids in and out of the wellbore provide valuable information about downhole conditions, which leads to safe and efficient operations.

Common oilfield technologies, such as rotating control devices (RCDs), mass flow meters, automated drilling chokes and downhole isolation valves, individually provide incremental safety and efficiency in downhole operations. When combined to work conjunctively, the tools can create a closed mud-return system that captures and redirects the free flow of drilling fluids, cuttings and hydrocarbons from the wellbore annulus. Closing this loop establishes a contained circuit of incompressible drilling fluid.

When an intelligent control unit (ICU) is added to the closed-loop configuration, the result is a self-contained system capable of detecting minute downhole pressure and volume changes.

The Microflux system helps the mud system to become a highly sensitive instrument to implement proactive managed pressure drilling (MPD) strategies.

Closing the loop on risks and hazards

A kick during drilling and completion operations poses a major risk to rig personnel, the environment and the equipment. That risk can be exacerbated by inadequate downhole data.

With a closed-loop system, kicks and losses are more readily and accurately diagnosed. This is a significant advantage given that slow detection or a misdiagnosis can jeopardize the safety of personnel and the viability of drilling operations. A slow or incorrect response can also inflict irreparable damage to the environment and cost millions of dollars in nonproductive time (NPT).

An MPD system with an intelligent control unit is a self-contained system that allows engineers to distinguish between ballooning, breathing, and influxes and losses to make more informed drilling decisions.

The capability of monitoring, detecting and quickly reacting to pressure changes in the standpipe and at the surface enables the downhole pressure profile to be proactively managed and manipulated. More control helps the operator and driller to navigate safely and successfully through known and unknown hazards.

To ensure the most accurate and expeditious response, more downhole knowledge and control is a must, especially as drilling reach extends to greater depths, higher temperatures and pressures, and more extreme locales.

Early detection of wellbore pressure fluctuations can have particularly significant impacts on deepwater operations, where it is not uncommon to encounter high temperatures and high pressures or formations bearing H₂S. In these operations, drilling windows are typically narrower and more difficult to drill, and the rig rate constitutes a significant expenditure.

Acquiring real-time data at the surface yields a better understanding of downhole pressure and how the formation and wellbore are responding to the drilling program. The speed and effectiveness of pressure management are enhanced for both conventional mitigation methods (i.e., mud weight and chemistries and BOP procedures) and MPD methodologies made possible by the closed-loop system.

Controlling equipment with instrumentation

Proactive pressure management via the fluid system starts with an RCD placed above the BOP to close the circulating fluid loop. The RCD’s elastomeric sealing elements and bearing assembly provide a pressure-tight barrier between the wellhead and the drill string. This barrier eliminates open-to-the-atmosphere mud returns to create the closed-loop system. With the RCD in place, drilling fluids, cuttings and hydrocarbons are safely circulated away from the personnel on the rig floor.

A variety of RCDs have been developed to work with different pressures, temperatures and wellhead diameters. Weatherford recently developed the first marine RCD for riser applications on floating rigs, which is also the first RCD to receive API certification. It addresses deepwater requirements for installation and maintenance and accounts for heave compensation in the riser.

The Model 7875 below-tension-ring RCD is integrated with a floating vessel’s riser system below the surface of the water, enabling the use of a closed-loop drilling system in deepwater applications.

Another key element of the closed-loop system consists of standard pressure sensors and mass flow meters to acquire wellbore mass balance information. These meters measure mass flow past a fixed point per unit of time. The closed-loop system denotes minute changes in bottomhole pressures at the surface within seconds, while volume variations of only gallons can be detected almost immediately.

Adding an annular choke manifold to this scalable closed-loop system marks a shift to pressure management using an MPD approach. The choke enables manipulation of backpressure, which provides dynamic control of the wellbore pressure and flow.

An ICU completes the equipment circle for the closed-loop system. This control unit houses the necessary data to measure and analyze physical properties and to react to adverse well events. The ICU uses proprietary algorithms to identify and relay the slightest downhole change and allows the engineer to distinguish between different events, such as ballooning, breathing, influxes and losses. In automated mode, the ICU controls the MPD chokes to regulate backpressure as needed. If, for instance, a small influx is detected, applying backpressure can minimize the influx to small volumes and allow the gas to safely circulate out of the system.

The integration of instruments and software enables automation of the system and the acquisition of real-time data. In difficult wellbore environments, this feature proactively identifies and manages influxes and losses for potentially faster responses to help retain control. The result is safer operating conditions. Additionally, mud weights can be optimized to improve drilling efficiencies and lower fluid costs.

The accuracy and immediacy of the data provides a high degree of insight into what’s happening downhole and improves the options to respond with more flexibility than simply weighting the mud system. On a fixed rig, the closed-loop system detected kicks at just 0.25 bbl of influx. On a floating drilling unit, where vessel heave movement introduced a 25 bbl/min peak-to-peak variation, a kick was detected at less than 3-bbl influx.

Because the majority of well control incidents occur during tripping, a downhole isolation valve (DIV) is commonly employed in closed-loop operations. The DIV protects against swabbing while pulling out of the hole and can be installed as a permanent or retrievable component to selectively isolate the wellbore. The valve is opened or closed as needed to enable tripping at conventional speeds. Maintaining tripping speed helps to prevent delays that can aggravate well control events and cause excessive NPT.

Data flow in real time

Avoiding trouble rather than mitigating causes of NPT and well control issues is a cost-effective strategy, especially considering the expenditures associated with offshore operations.

Offshore Egypt

HPHT conditions and wellbore ballooning in a tight operational window led some to question the economic viability of a field offshore Egypt. Several attempts to drill offset wells in this field were unsuccessful as a result of kicks and losses. Any sign of loss or gain was treated with caution because the potential consequences of a gas influx and subsequent expansion at surface could have resulted in a well control incident. Pore pressure ranged from approximately 17.6 ppg to 18.4 ppg, and the fracture gradient ranged from approximately 18.0 ppg to 18.6 ppg.

To continue with the drilling campaign, the operator revised its approach and employed a closed-loop system. During the operator’s first application, the closed-loop system detected kicks and losses with a semi-automated choke, enabling the necessary pressure management.

The operator’s second application used the fully automated capabilities of the system. The MPD approach enabled the operator to use a statically underbalanced mud weight and adjust annular backpressure at the surface to create a virtual mud weight. Adding or releasing annular surface pressure on the closed-loop system resulted in an almost immediate response in bottomhole pressure.

The 10 ^5/8 in. x 12 ^1/4 in. and 8 ^1/2 in. hole sections were successfully drilled to total depth (TD). In addition to helping reach the targeted casing points, the closed-loop system was used to fingerprint wellbore ballooning and breathing during connections.

Previously used drilling methods misdiagnosed these incidents as kicks and losses. However, the accuracy of the data obtained with the closed-loop system enabled the operator to continue the drilling campaign with a more effective and safer strategy.

Offshore India

The complex geology in the Asia Pacific region is prone to tectonic activity, heavily faulted and folded strata, lost circulation zones and uncontrolled mud flows. The conglomerates, igneous and carbonates prevalent in this region present many drilling challenges. MPD is the preferred methodology to mitigate severe circulation losses associated with fractured carbonate formations. More than 100 MPD wells have been drilled since 2005. Wells that experience kick/loss and near- or total-loss scenarios are now being drilled safely and efficiently.

An MPD application offshore India significantly reduced time lost to downhole problems to one day. Mitigation of similar problems in previous offset wells averaged 10 days. The significant reduction in troubleshooting was achieved by reducing kick/loss cycles and other flat time associated with narrow pore pressure/fracture gradient. Time was also saved when more control of the mud weight led to an increase in ROP.

Fractured carbonate reservoirs offshore North Africa are being drilled using MPD methodologies. In one well, low bottomhole pressure and H₂S gas contributed to mud losses of 1,400 bbl/hr and a low ROP. MPD methods eliminated expensive mud losses, prevented sour gas from reaching the surface and increased the ROP from 40 ft/day to 220 ft/day (12 meters/day to 67 meters/day).

Onshore shale plays

Although the daily rig rate is not as high and depths are shallower, drilling objectives for land operations mirror those set for offshore campaigns – safely reach the planned depth, within budget, and find enough producible reserves for adequate return on investment.

The shale gas plays in Northwest Louisiana and East Texas have seen wells drilled into formations with low permeability and high porosity. These characteristics typically create over-pressured zones that have obvious drilling concerns. The unconventional gas target known as the Haynesville shale requires a horizontal step-out in excess of 10,000 ft MD. A recent successful drilling strategy employed MPD techniques to target this Upper Jurassic formation that contains significant microfracturing.

RCDs without a flow meter or software have been used as a means to apply backpressure on an as-needed basis. Wells typically employed 16.5-ppg oil-based mud (OBM) when drilling out the 7-in. casing shoe and making 6 ^1/8 -in. hole. With the first deployment of the closed-loop system, the shoe exited with just 14.8-ppg OBM. The intent was to hold that mud weight through the build section and horizontal to TD.

Better downhole visibility and control in gas-prone sections resulted in several improvements. By enabling the use of a lighter mud weight, the rate of penetration (ROP) increased from about 15 ft/hr to as high as 60 ft/hr. Improved drilling rates and less NPT associated with well control cut drilling time in half. The well reached TD in 16 days as opposed to the planned 31 days. This time reduction was attributed to an increase in the ROP as a result of drilling with a lower mud weight and detection/depletion of microfractures in a controlled and safe manner.

The Barnett Shale in East Texas also yields significant gas reserves. MPD has reliably identified high-pressure kicks, allowing the wells to be safely shut in. In one instance, an overbalanced well lost 200 psi when the pumps were stopped. When flow declined as expected and then unexpectedly began to increase, the well shut in.

In the three minutes that transpired from stopping the pump to shut in, the well gave a 35-bbl kick. The ability to immediately see the flow and to expeditiously react by closing the BOP prevented the kick from becoming a major well control event – an all too frequent outcome in the area.

Beyond the horizon

Although drilling objectives are being pushed further and into more complex conditions, they are attainable without putting personnel at risk or jeopardizing the environment. Continual development of enabling technologies and processes, including both the closed-loop system and MPD methodologies, has put previously inaccessible reserves within reach.

A subsea RCD close to commercialization will be installed above the subsea BOP and enable riserless drilling while enhancing operational safety. A sub-based continuous flow system in development will reduce wellbore instability issues and enhance HSE. More sophisticated monitoring, analysis and management software will further extend the capabilities and applications of the technology.

Access to more accurate downhole data and the ability to manage drilling pressures will allow operators to not only see beyond the horizon but to produce it.

Microflux is a registered trademark of Weatherford International.

By Federico Mezzatesta, National Oilwell Varco

Figure 1 shows basket acceleration vs loading. On a conventional shaker (black KC 2.5 HP Standard line), G drops as weight on the basket increases because the motor rpm and force are constant. Acceleration reduces immediately due to loading. With the VSM Multi-Sizer (blue VSM-MS line), incorporating CGC, the basket runs at a lower acceleration (G) and automatically ramps up to a higher G when needed to process the drilling fluid.

For the first time in the industry, shakers have the ability to automatically increase acceleration (G) under loaded conditions because of Constant-G Control (CGC). The technology was developed to maintain an optimal G rating on National Oilwell Varco (NOV) FluidControl Brandt shaker products during varying liquids and solids loading conditions.

CGC, developed by NOV’s Fluid Control Group, maximizes shaker screen performance, solids conveyance and throughput while enhancing screen life. A combination of field and pilot plant tests have shown an ability to increase shale shaker capacity by up to 35% or filter drilling fluid at 2 to 3 API screen classes finer than a conventional shaker.

How does CGC work?

On a conventional shaker, G drops as weight on the basket increases because the motor rpm and force are constant. The result is a unit that is less efficient while loaded and has a reduced ability to process drilling fluids. The immediate reduction in acceleration due to loading on a conventional shaker is displayed by the KC 2.5 HP Standard line in Figure 1. As loading increases, G drops because motor force is constant and does not compensate for the additional weight.

To overcome this problem, the company added an accelerometer on the basket tied to the variable frequency drive (VFD) operating the motors. By doing so, the VFD is able to constantly monitor the basket G and adjust the motor speed to compensate for the fluids and solids loading the basket. The basket runs at a lower G and reduces wear on screens and components while operating with little solids loading and automatically ramps up to a higher G when loading becomes more extreme and higher Gs are needed to process the drilling fluid.

This is shown by the VSM Multi-Sizer (VSM-MS) line in Figure 1. The unit operates at 5.3 G with up to 100 lbs of fluid and solids loading on the basket, 6.3 G when loading is between 100-300 lbs and 7.3 G when loading exceeds 300 lbs and will maintain that G with up to 500 lbs of loading. Acceleration decreases beyond this point as motor speed cannot be increased any further.

Why it matters

Figure 2: Dryness samples collected during fluid end point capacity tests were similar for all G set points. Regardless of G, the dryness was consistent when the fluid end point value was maintained.

Shale shakers are the first and best defense against drilled solids. By increasing the shale shaker’s processing capacity, CGC enables better control of drilled solids, which has the potential to reduce rig nonproductive time (NPT), improve rate of penetration (ROP) and reduce drilling fluid costs. In addition, the ability of CGC to selectively increase or decrease G depending on loading conditions reduces wear and tear on screens and shale shaker components.

In pilot plant testing, CGC allowed for up to 35% higher fluid-processing capacity. Field tests have shown that CGC would enable the use of screens 2 to 3 API classes finer than similar shakers not equipped with CGC.

Pilot plant test results

Pilot plant and field tests have been conducted since December 2007 to measure the value added by CGC. Capacity, conveyance, cuttings dryness, screen life and motion comparison were tested to determine their relationship to changes in the G.

Flow, screen selection, basket angle and all mud properties were controlled in pilot plant testing. Results from the pilot plant showed the various relationships between the change in G and the tested variables.

Capacity, conveyance and cuttings dryness

In pilot plant tests, testing revealed that a higher G increased the shaker capacity. However, the relationship is not linear. The law of diminishing returns applies to capacity as the G increases. As the G increases, the rate of increase in capacity decreases to eventually a flat line when the G reaches a threshold point. Pilot plant testing confirmed that CGC increases shaker capacity up to 35% without any appreciable difference in screen life.

To measure capacity in the pilot plant, a constant fluid end point was selected for all Gs, and the flow was measured to determine the capacity at the selected G. The flow was measured after the fluid end point, and the G was stable for 10 min.

Field testing confirmed the results of the pilot plant. The rate of change in the fluid end point decreases as the G increases, but the screen life is not affected by the increase of G. Since controlling and measuring the flow in the field is difficult, measuring the fluid end point is a reliable measure of change in capacity assuming there is no major change in the flow. Most data collection was done in a short time frame to ensure consistency in the flow.

Figure 3: A field capacity test of the three King Cobras was conducted, two with CGC and one without. The two equipped with CGC processed 100% of the flow at 980 gal/min, or 18% more than the non-CGC-equipped shaker.

Testing for conveyance was measured by dropping a Ping-Pong ball (or similar object) at the fluid end point and measuring the time it took to travel to the end of the shaker. By knowing the distances (in.) and time (sec) it took the object to travel, the conveyance was calculated in in./sec. Testing was conducted over linear and elliptical motion in the pilot plant and linear motion in field tests.

Testing showed conveyance is dependent on both the G value and the square of the G value. The relationship generates a gentle, upward sloping curve, which the company was able to obtain with an R² value, or accuracy, of 97%. Testing also showed very similar conveyance results for both linear and elliptical motions. For simplicity purposes, if the G² value is ignored, a linear regression equation can be applied to the pilot plant results, which yields the following formulas:

Conveyance = 0.7075 * (G) – 1.1485 for linear motion with R² of 83% and

Conveyance = 0.7108 * (G) – 0.9551 for elliptical motion with R²of 85%.

Field tests confirmed the pilot plant results, and a linear regression equation can be written as:

Conveyance = 0.3468 * (G) + 0.402 with a R²of 82%.

Differences between pilot plant and field test results can be attributed to the difference in mud properties and the screens used. In the pilot plant, API 100 screens were used, while API 120 screens were used in the field test. Pilot plant tests used water-based mud (WBM) while the field tests used oil-based mud, which shows that the generally linear relationship still holds regardless of mud type.

The cuttings dryness was measured by collecting the cuttings from the discharge end of the shaker. The cuttings collected were weighed and dried. The dried cuttings were re-weighed, and the new mass was divided by the old mass to get the percent of dried solids.

The sample of wet cuttings was placed in a drying oven at 355°F until it was dried. The dryness samples collected during the capacity tests of the fluid end point were similar for all G set points (Figure 2). The dryness was consistent regardless of G when fluid end point is maintained the same. In addition, pilot plant testing showed there was no appreciable difference in cuttings dryness between linear and elliptical motions. Field tests were not able to confirm pilot plant results as they lacked the steady-state conditions necessary to obtain accurate data.

Field test results

A side-by-side flow capacity field test of the King Cobra 2.5 hp, the King Cobra 2.5 hp with CGC and the King Cobra Venom 3.5 hp with CGC was held by a major drilling contractor in Oklahoma. Each shaker attempted to process 100% of drilling fluid returns at a rate of 980 gal/min using API 100 screens while drilling a 17 ½-in. top-hole section at a rate of 100 ft/hr with WBM.

While the King Cobra 2.5 hp without CGC managed to process 85% (830 gal/min) of the returns, both King Cobra shakers with CGC processed 100% of the flow at 980 gal/min (18% more than the non-CGC equipped shaker).

In addition, the King Cobra 2.5 hp with CGC managed to process 980 gal/min with the fluid end point on the third screen, while the King Cobra 3.5 hp with CGC managed the same with the fluid end point close to the end of the second screen. This represented a 25% and 50% increase in unused screen area, respectively, relative to the non-CGC equipped shaker (Figure 3). This increase in unused screen area would have allowed the contractor to dress the shakers with screens 2-3 API sizes finer than the non-CGC equipped unit and still process the same flow rate.

Due to performance, the contractor chose the King Cobra Venom 3.5 hp for all newbuild rigs and replacement shakers on existing rigs.

CGC testing also was conducted on the VSM Multi-Sizer separator, a triple-deck separator consisting of a scalping deck and two lower decks, the latter of which can be operated in series or parallel modes. During a multi-well test on a land rig in Zapata County, Texas, a VSM Multi-Sizer was set up to receive 100% of drilling fluid returns. With the unit operating in parallel mode and CGC engaged, it was able to handle 100% of returns through every section of the well.

In the 12 ¼-in. top-hole section, the unit processed 100% of returns at 850 gal/min using API 140 screens while drilling with a ROP of 150-300 ft/hr. This was six API screen classes finer than standard operating practice with the rig’s original single-deck linear motion shakers.

The intermediate and lower hole sections were drilled with the same ease; CGC always allowed the unit to exceed the rig’s process requirements. The intermediate 8 ¾-in. section was drilled at a rate up to 760 gal/min with a ROP of 75-350 ft/hr and API 140 screens (two sizes finer than the original shakers). In addition, the lower 6 ½-in. hole section was drilled with up to API 200 screens (three classes finer than the original shakers).

CGC also was tested offshore as part of the VSM Multi-Sizer separator in the UK sector of the North Sea. Two VSM Multi-Sizer units were set up alongside three VSM 300 shakers to evaluate the performance of the CGC-equipped separators. A single VSM Multi-Sizer was able to process 100% of returns during the 16-in. well interval, which was drilled from 3,230 to 11,050 ft. The flow rate handling capacity in the 16-in. well interval was measured at multiple pump rates ranging from 800 to 980 gal/min; 10-mesh scalping screens were used. Two 800 gal/min tests ran API 60 filtering screens with drilling rates of 130 ft/hr and 12.5-ppg fluid. Three 950 gal/min tests used API 170 screens to process 13.15-ppg fluid at rates up to 120 ft/hr, and a fourth 950 gal/min test used API 200 screens with an ROP of 60 ft/hr to process 13.15-ppg fluid. CGC enabled the VSM Multi-Sizer to never experience flooding conditions.

Summary

Shale shakers are the first and best defense against drilled solids. A study showed that CGC-equipped shakers can process fluids at rates up to 35% higher and with screens 2 to 3 API classes finer than conventional shakers. By increasing the shaker’s capacity, CGC enables better control of drilled solids. Since its introduction into the market in 2009, CGC has been adopted on more than 150 shakers onshore US as well as offshore.

Constant-G Control, Brandt, VSM, King Cobra, and King Cobra Venom are registered trademarks of NOV.

Operator requests have led to the manufacture of more advanced and durable fluids. “Green” lubricant chemistries are emerging that hold the promise of both environmental and technical performance. Courtesy of Panolin

Just as the environmentally responsible use of lubricants in daily offshore rig operations and use of zero-spill methods is an ongoing responsibility of the drilling contractor, progress in available chemistries of lubricants is an ongoing effort on the part of industry suppliers. Increased options from suppliers are helping contractors marry environmental responsibility with performance.

More than 250 types of lubricants are used in daily offshore rig operations in appreciable volumes, including engine oils, hydraulic fluids, thruster fluids, pipe dope, gear oils and greases. According to Jon Pearce, marine and energy lubricants product manager for Castrol, the newer rigs being built today have large 3,000-gal hydraulic power packs on the drill floor that sit directly above the moonpool or on the drill floor directly above the sea. The new semisubs have complex hydraulic systems that incorporate heave compensation, and derrick and hydraulic rig mains can have 10,000 gal of oil in them. “When a 6-in. hose burst on one of those, it released 5,000 gal onto the deck of the rig in 20 seconds. It’s not just about system volumes, it’s the huge flow rate that affects the scale of a spill.”

According to lubricant suppliers, switching out the use of older lubricant technology fluids to newer alternatives can deliver comparable if not better performance. The fact that the industry has experienced disappointments with “green” lubricants makes spreading the word of chemistries suited for offshore rigs even more important.

“Historically, green lubricants existed, but they had quite a bad name because typically they didn’t work well in the applications for which they were designed. That’s been quite a hurdle to get over because people think that green lubricants aren’t as good as a conventional product,” Susannah Linington, environmental specialist for Castrol, said. “We found that products that were designed using vegetable oil were great environmentally but technically don’t give the performance required for offshore rig applications.”

There has been a huge development in the type of chemistries used during the last few years that offer both environmental and technical performance,” according to Ms Linington. “A lot of the activities in which we are involved is educating people that the new types of green lubricants are designed with completely different base chemistries that give both the desired environmental performance and the technical performance that works in specific applications,” she said.

Chauntelle Baughman, account manager for Hydraquip, agrees, noting that the greatest challenge in the acceptance of biofluids has been an overall lack of education on the subject and that every effort should be made to promote education on biofluids through the energy industry. “Knowledge of basic fluid properties and their toxicity will position contractors and operators to make environmentally considerate decisions,” she said. “While companies are aware that biofluids are available and becoming increasingly mandated, there is still much confusion about terms such as biodegradability and toxicity and how standards are defined.” Hydraquip is a distributor of hydraulic components and a line of Panolin biodegradable lubricants.

Environmental regulations have been the primary driver behind the use of biofluids. Operator requests have led to the manufacture of more advanced and durable fluids. The use of environmentally friendly fluids overall has largely been the result of governmental regulations restricting and reducing environmental impact, according to Ms Baughman.

In addition to meeting various environmental regulations around the world, advantages to using the green lubricants include fire resistance, rust prevention, longer lubricant life, better system performance over time, and stability in high-heat applications.

Biofluid development

Several environmental risk areas exist onboard an offshore drilling rig. Systems that result in high levels of discharge or a high probability of entry into the sea (red) are considered to be high risk. Applications that contain relatively small lubricant volumes and from which, under fault conditions, the lubricant could not enter the sea are considered to be very low risk (green). Between these extremes are those systems that present significant risk, as anything spilled or leaked directly enters the sea (orange).

According to Mr Pearce, about 20 years ago the industry started working on hydraulic oils based on vegetable oils as an environmentally friendly alternative to mineral oil, and the equipment in which they were used had to be designed around the oil because of their performance limitations. There was never widespread adoption, and the fluids were used only where needed.

“Hydraulic systems were the first systems for which the industry required green solutions,” Mr Pearce commented. “But it became apparent that other equipment (specifically items sitting below the water line on floating rigs, such as thrusters) have leakage because they are deliberately pressurized to keep water out. As a result, there is more focus on what can be called operational discharges as opposed to big spills. As this need surfaced, the solution called for a whole range of green products.”

These oils were less toxic and did not create as much of a sheen but were not truly biodegradable, Mark Miller, chief executive officer for fluids manufacturer Terresolve Technologies, said. “This was a first step in environmental improvements; it was a better technology for environmental performance but was a step down in equipment performance.”

In the late 1990s and early 2000s, readily biodegradable oils surfaced on the market. “I would not say that there was a wholesale shift, but a lot of the pioneers looked to find an environmental alternative for applications in the offshore rig arena,” he continued. “Then along came the perfect storm.”

This was the coincidence of three elements. First, the technology was evolving to where it was suitable for use on drilling rigs. Second, drilling contractors and service companies were looking for further improvements in the environmental arena. Finally, there was a groundswell of US and international agencies pushing for the industry to go greener, according to Mr Miller.

Until recently, most biodegradable hydraulic fluids, gear oils and greases were based on vegetable-oil technology. These technologies are useful in certain applications but typically are poor for use on offshore drilling rigs because 1) rig equipment runs very hot, and vegetable oils cannot take extreme temperatures, 2) there is a good possibility that the lubricants will get wet as the rig and equipment operate in a humid environment, and 3) the change-out interval is very lengthy, according to Mr Miller.

People moved away from the vegetable oil-based fluids in two directions: synthetic ester and biopolyolefin technologies. Terresolve went forward with biopolyolefin technology because it is biodegradable, non-toxic, non-sheening and can take heat, cold and contamination from water and old oil. Hydraquip and Castrol went with synthetic esters. Hydraquip’s synthetic fluid is made from saturated esters and is readily biodegradable, non-toxic, and zinc-free. Castrol also has a suite of synthetic-based hydraulic fluids and lubricants that includes a topside hydraulic fluid and a thruster-specific fluid.

A hindrance to mass use of biofluids

“Some suppliers don’t get the industry all that well, and products that fail give us all a black eye,” Mr Miller noted. “We have to explain that there are fluids out there with different characteristics. Some of them are very good and durable, and some of them fall apart when they get wet. When you’ve got a billion-dollar piece of machinery that’s making $300,000, $400,000 or $500,000 a day, you can’t risk downtime,” he said.

Ms Baughman agreed. “Not all biofluids are created equal. There are some that react poorly to high temperatures, some that are unstable in certain environments, and some that have poor performance characteristics. There have been performance reliability issues in the past because there is a general lack of education regarding the different types of biofluids and which of those fluids are best suited to specific applications.”

Advantages of “green” lubricants vary depending on the type of biofluid being used. “We look at the weaknesses of certain biofluids, but we never stop and say why it is worth it,” Mr Miller said. “Green lubricants typically have better lubricity that equates to reduced wear and reduces operating temperatures, which can prolong equipment life. These lubricants also have a higher viscosity index (how the thickness of oil changes with regard to temperature), so the fluid will stay within the designed thickness and viscosity over a broader temperature range.”

Understanding the terminology

“I think it’s fair to say that the majority of the industry associates environmental performance with biodegradability. To state that something is inherently biodegradable is getting accepted, when in fact, any oil-based product is inherently biodegradable. It just takes a long time to degrade,” Mr Pearce noted. “The level of awareness needs to be raised about what is and isn’t environmentally responsible.”

“People seize on just one statement like saying that something is biodegradable,” Ms Linington said. “Food grade is a misconception. Many say, ‘oh, it will be fine’ when confronted with food grade as an option. But humans are very different organisms than algae. What can be perfectly safe for a human to eat can be very toxic to an algae or a smaller organism living in the plankton. That’s why it’s important to test the product in seawater.”

“There is no scientific definition of what environmental responsibility is,” she continued. “People have different conceptions of what is considered environmentally responsible. It’s important to say that this product is going into the marine environment, and therefore, the marine environmental impact will be at the point that it goes into the sea. Biodegradation, toxicity and bioaccumulation need to be considered and they need to be measured in seawater, not fresh water or soil, which are quite easy tests to pass.”

“It’s important that contractors ask lubricant suppliers the right questions,” Ms Linington continued.

First, what is biodegradation? “It seems like a simple question that should have a simple answer,” Ms Baughman commented. Actually, there are two standards for biodegradability: inherently biodegradable and readily biodegradable. “While some fluids are biodegradable, that does not necessarily indicate that they are non-toxic. According to the US Army Corps of Engineers standard, a hydraulic fluid is considered to be non-toxic if a specific ratio of the hydraulic fluid to water is used and less than 50% of the test organisms die within 96 hrs,” she said.

“Ideally, you want 60% of any of the chemicals within a formulation to have broken down naturally when they go into the sea,” Ms Linington said.

“Inherently biodegradable” means that the product has the propensity to biodegrade; no specific time frame or degree is given for the breakdown. Petroleum-based lubricants may be inherently biodegradable; however, they persist in the environment for years and require long-term remediation.

“Readily biodegradable” fluids break down rapidly when they enter the environment. Four types of readily biodegradable fluids are conventional vegetable-based fluids, synthetic esters, polyalkylene glycol and polyolefin.

Vegetable-based fluids are readily biodegradable, but, when exposed to heat, begin to break down to the point of destruction; they can only withstand operating temperatures under 160°F and they become unstable when exposed to water or moist environments.

Synthetic esters are also readily biodegradable and non-toxic and are available in two categories: saturated and unsaturated. Unsaturated ester products tend to oxidize quickly, while saturated ester products resist oxidation. Some synthetic fluids may form acids as a result of exposure to moisture, but all acids created are not the same. Hydrolysis of esters does not always lead to corrosive acids; sometimes acids formed can improve anticorrosion capabilities, according to Ms Baughman.

Polyalkylene glycol exists in both biodegradable and non-biodegradable form. It is intolerant of conventional petroleum oils and vegetable oils, is very soluble and is typically incompatible with seals and filters used in marine equipment.

Biopolyolefin is biodegradable, non-toxic and tolerant of water and contaminants. It is stable in all temperature ranges, climates and seal compatibilities. It is also compatible with conventional petroleum and most other biodegradable products.

The second important question relates to toxicity. Toxicity is the degree to which a substance can damage an organism. It can refer to the effect on a whole organism, such as an animal, bacterium or plant, as well as the effect on a substructure of the organism.

Mineral oil is quite toxic, especially in combination with conventionally used additives, Ms Linington said.

“We test all components in our formulations on four different species across the food chain. It’s important that you test all levels from algae to fish at the top of the food chain,” Ms Linington commented. “The last thing we look at is bioaccumulation potential, the potential for a chemical to build up in the fatty tissue of an organism and gradually over time have toxic effects. This can go right up the food chain into humans … bioaccumulation is something that people tend to ignore; they focus on biodegradation.”

Regulations regarding lubricants

Environmental legislation related to lubricants surfaced in the 1990s, according to Ms Linington. Today, regulatory guidelines specifically related to hydraulic fluids and lubricants have been issued in the northeast Atlantic region, the Gulf of Mexico, Norway, and Canada. Also, any pollution in international waters is covered by the International Convention for the Prevention of Pollution from Ships (MARPOL).

“Really you’ve got three situations, two of which are covered by regulations (blowout preventer control fluids and oil spills into the sea),” Mr Pearce said. “Small-scale oil releases (such as from thrusters and hydraulic line leaks) fall in between existing regulations.”

Finding formulations that work

While “green” lubricants have been available for some time, significant advances have been made in their chemical composition, according to Ms Baughman. When selecting a biodegradable fluid that meets the needs of the offshore drilling industry, things to look out for include the fact that synthetic esters are often grouped together despite the significant performance and longevity differences between saturated and unsaturated.

Whether the product is saturated is determined by chemical bonds within the fluid itself. Unsaturated esters have multiple open bonds that interact with oxygen quickly, leading to oxidation (aging) of the fluid. Aging is the cause of extreme thickening and gumming of the fluid, along with deposits of shellac, which lead to catastrophic system failures, according to Ms Baughman.

“Ask the fluid manufacturer for the Iodine Number,” she said. “It identifies the number of open bonds available, so the higher the Iodine Number, the greater the number of bonds that can interact and oxidize. Generally speaking, a saturated ester product has an Iodine Number of less than 15.”

Another thing to determine is whether the fluid will be compatible with seals in existing equipment. The biofluid supplier should be able to provide testing documentation and manufacturer approvals, Ms Baughman said.

Also, hydrolytic stability should be considered when selecting a biofluid, she continued. Hydrolytic stability is the ability of a fluid to resist decomposition in the presence of water. To measure the degree of hydrolysis in a biodegradable ester, for instance, the total acid number (TAN) should be reviewed. When oils are mixed with water and heat, they are cleaved, or bonded, and new chemicals are formed as a result of this reaction. These chemicals can include glycols and fatty acids. When looking at TAN results, a high number indicates that a large number of ester molecules have cleaved, meaning that the chemical composition of the fluid has changed.

In the case of mineral-oil-based lubricants, the TAN should not exceed 2 mgKOH/g (milligrams of potassium hydroxide per gram) but the TAN values of biodegradable alternatives may increase up to 5 mgKOH/g without leading to any problems, Ms Baughman said.

“It is important to note that before hydrolysis of synthetic products will cause any issues in a hydraulic system, the amount of water needed for that hydrolytic process to take place will cause major cavitation, corrosion and other catastrophic issues before the fluid even begins to react…. In principle water is a harmful contaminant, reducing the life of the hydraulic fluid and the mechanical components,” she said.

Cost versus performance

“The reality is that a good-quality biodegradable fluid is going to cost more than a good-quality petroleum oil,” Ms Baughman said. “But you’re going to get a lot of benefits from the biofluid like improved performance, potentially longer change-out intervals and better operation at reduced environmental risk. So, in the long term there is actually a cost savings.”

Making the effort

Most operators and contractors would agree that it’s better to stay ahead of the curve when it comes to understanding environmental properties of chemicals used in daily operations, discerning levels of discharge and probability of spills, selecting the best chemical options based on the level of environmental compliance and equipment performance, and maintaining zero-spill solutions.

“I think the industry overall is doing a phenomenal job from the environmental perspective. I firmly believe that the industry has not given itself enough credit for all of the environmental initiatives that it has taken and accomplished,” Mr Miller remarked.

A contractor in search of alternatives

While some “green” chemistries have not performed as expected, there are environmentally safe rig fluid alternatives that do work. According to Mr Miller, Noble Drilling had been looking for a non-toxic hydraulic fluid for use in the exposed areas on its rigs; several products were tried, but in the end, they did not meet Noble’s needs because they broke down quickly in the harsh offshore environment.

“Despite the fact that they experienced a significant failure, Noble was still willing to try it again,” Mr Miller said. “They did a limited program with us which was a sweeping success. Now they are starting to do some change-outs across their fleet.”

“I like to say that today’s chemistries are not your daddy’s biofluids,” Mr Miller quipped. “There were no doubt problems with earlier versions of the green fluids. The lubricants industry has realized that the needs of a drill rig are different than some of the other applications. We have to be smarter and make our fluids more durable… Some of us have taken that challenge, gone back to the lab and made the fluids work better.”