Other findings of the report included:

• A noticeable and steady reduction in the incidence of over-three day injuries to an all-time low;

• No fatalities and a reduction in combined fatal and major injury rates, and in all types of dangerous occurrences; and

• An all-time low in Level 3 verification non-compliances that relate to performance standards of safety-critical equipment identified by an independent competent person.

“In all this progress, our industry’s safety organization, Step Change in Safety, has played a leading role, and most of the improvement is down to the focused, collaborative effort of companies, workforce representatives, trade unions and the Health and Safety Executive in Step Change,” Mr Paterson said. “However, there is no room for complacency. While the review that followed the Piper Alpha disaster provided the foundation for what is now one of the most robust offshore health and safety regimes in the world, the approaching 25th anniversary of that tragedy only serves to remind us that we must never stop at striving to make things safer. Continued engagement of all parties through Step Change in Safety will be crucial in that effort.”

The license partners of Gullfaks and Oseberg Area Unit have acquired two new Category J jackups. The rigs will be owned by the licenses and will contribute to increased recovery and extended field life.

KCA DEUTAG awarded contract worth up to US $2.2 billion

KCA DEUTAG has been awarded a contract with Statoil for the management, operation and maintenance of two Category J jackups, which will operate on the Norwegian Continental Shelf (NCS). The contract is for eight years with the option to extend by four periods of three years, giving potential for the contract to last up to 20 years. The contract value is US $900 million (NOK 5.2 billion) for the initial period and US $2.2 billion (NOK 12.8 billion) including options. Operations are expected to start in 2016 to 2017.

The new Category J rigs will be able to operate in harsh environments at water depths from 230 to 460 ft (70 to 140 meters) and drill wells with lengths up to 32,800 ft (10,000 meters). Each tailor-made rig will be owned by the Oseberg and Gullfaks licenses and be specifically designed to operate on both surface and subsea wells.

The contract adopts an innovative approach where the licenses own the rigs instead of the drilling contractor. “This is an important milestone for both Oseberg and Gullfaks. The awards will secure vital rig capacity for both licenses at very competitive prices. Reduced drilling costs are important to increase recovery and to maintain production in Oseberg Area Unit and Gullfaks for decades,” Øystein Håland, head of Operations West in Statoil, said.

During the initial engineering and construction phases, a joint Statoil and KCA DEUTAG team will work alongside Samsung Heavy Industries and National Oilwell Varco at the shipyard. “This award enhances our already significant business in Norway and also sets a precedent for KCA DEUTAG to target further drilling operations and management contracts on newbuild mobile offshore drilling units that are third-party owned,” Norrie McKay, CEO of KCA DEUTAG, said. KCA DEUTAG also operates eight other platform-drilling rigs for Statoil on the NCS.

Keppel FELS’ Super A Class jackup has been delivered to Discovery Offshore 46 days ahead of schedule.

Keppel delivers first KFELS Super A Class jackup for harsh environments

Keppel FELS has delivered its first KFELS Super A Class jackup to Discovery Offshore, which is managed by Hercules Offshore.

Discovery Triumph has been delivered 46 days ahead of schedule and with a perfect safety record. The ultra-high-specification jackup has been designed for the harsh environmental conditions of the North Sea (UK sector). Its enhanced leg design incorporates Keppel’s high-capacity rack and pinion jacking system, which ensures that the rig is able to jack up and stand firm in a secure and safe manner in challenging environments.

“We are pleased that Discovery Offshore has selected this design for their first two harsh environment rigs,” Wong Kok Seng, managing director, offshore, for Keppel Offshore & Marine and managing director of Keppel FELS, said. “Although it is a new design, our expertise and strong engineering, construction and project management experience has enabled us to deliver it ahead of schedule while achieving an excellent safety record. We look forward to delivering the second KFELS Super A Class to Discovery Offshore just as efficiently.”

Discovery Triumph is capable of operating in water depths of 400 ft and drilling depths of 35,000 ft. The KFELS Super A Class is equipped with pinion overload detection, rack phase difference detection, and brake failure and overload protection devices. The rig has a 2 million-lb hook-load drilling system and includes a spacious deck and amenities to accommodate 150 workers.

“As this North Sea-compliant rig is able to operate efficiently in virtually all parts of the world outside Norway and the Arctic, we also see many opportunities for it to be deployed in other parts of the world to generate maximum utilization. With another KFELS Super A Class rig about to join Discovery Triumph later this year, we are well positioned to become a strong player in harsh environment drilling,” John T. Rynd, CEO of Hercules Offshore, said.

Keppel FELS is currently building another KFELS Super A Class jackup for Discovery Offshore, as well as another three for Ensco.

Diamond Offshore orders semisubmersible, secures three-year drilling contract with BP

Diamond Offshore Drilling has ordered a new Moss CS60E design harsh-environment from Hyundai Heavy Industries. The 10,000-ft dynamically positioned rig is expected to be delivered after November 2015. Projected capital cost of the unit, including spares, commissioning and shipyard supervision, is approximately US $755 million.

Diamond Offshore secured a three-year drilling contract with a subsidiary of BP to utilize the rig for initial operations off the coast of South Australia. The initial operating dayrate is $585,000 per day and is subject to upward adjustment for certain increased operating costs and equipment modifications.

“We are pleased to have been selected by BP for this important work,” Larry Dickerson, Diamond Offshore’s CEO, said. “Our company, and its predecessors, have been continuously active in Australia since 1982, drilling over 600 wells – far more than any other drilling contractor.”

BP also has exercised a one-year option for use of Odfjell Drilling’s Deepsea Stavanger. The extension will keep the rig with BP in Angola as a minimum until November 2014. Deepsea Stavanger has been drilling under contract with BP Angola since 2011. The rig is currently drilling and completing production wells on the Greater Plutonium field in Block 18. The contract has two more one-year options.

Atwood Oceanics secures contract for the Atwood Eagle

Atwood Oceanics has been awarded a drilling services contract for the Atwood Eagle semisubmersible. This contract is for 24 months and will be performed offshore Australia at a dayrate of approximately US $460,000. Contract commencement is expected in June 2014 in direct continuation of present operations, which have been split between BHP Billiton, Apache Energy and Woodside Energy. With the award of this contract, the firm contractual commitment for the Atwood Eagle is expected to extend to June 2016.

“The Institute will help federal regulators keep pace with new processes employed by the industry as they move into deeper water and deeper geologic plays that require technological innovation to bring projects into production,” Rear Admiral James Watson, director of BSEE, said. “I look forward to expanding the dialogue and engagement with additional stakeholders to identify and reduce risks to worker safety and the environment.” Interested applicants should register with the grants.gov website to submit an application.

The institute stems from a recommendation from the Ocean Energy Safety Advisory Committee (OESC), a federal advisory group comprised of representatives from industry, federal government agencies, non-governmental organizations and the academic community. The recommendation calls for establishing a body that will provide a program of research, technical assistance and education and serve as a center of expertise in oil and gas exploration, development and production technology. The institute will be an important source of unbiased, independent information and will not have any regulatory authority over the offshore industry.

“As offshore energy development becomes more complex, every effort should be made to make sure it is done ever more safely,” said Dr Thomas O. Hunter, chair of the OESC and former Sandia National Laboratory director. “The Institute provides a unique opportunity for all engaged parties to work together to identify and deploy technology that will make a real and enduring difference. The time is right and the opportunity is clear.”

This year’s technical program will include topics such as shale gas risk management, private equity investment in oilfield services and equipment companies, and decommissioning process optimization. Additionally, keynote speaker Stephen P. Thurston, VP of Chevron North America E&P Co, will address the short- and long-term outlook for the deepwater Gulf of Mexico.

Greg Stutes, Technical Session Committee chairman

“LAGCOE 2013 offers technical sessions to address topics of high interest to attendees. As technology changes in our industry, so does the need to convey the associated effect it has on all facets of our business,” Technical Session Committee chairman Greg Stutes, Completion Specialists, said. “Our technical session committee focuses on producing a slate of technical speakers and topics that have significant relevance to the current state of our industry and also tie in well with LAGCOE, an onshore and offshore exposition. The technology transfer associated with the technical sessions provides critical technical information that is of high interest to decision makers.”

In 2011, LAGCOE welcomed 400 exhibiting companies from around the world and 14,000 attendees from 26 countries and 47 states. Register for this year’s show here.

Statoil, together with partners in the Grane Unit, has made a new oil discovery in the Grane field in the North Sea.

Statoil and its partners are in the process of concluding drilling operations in exploration well 25/11-27 in the Grane Unit. Drilled by Songa Offshore’s Songa Trym semisubmersible, the well proved an oil column of 20 meters in the Heimdal Formation. The estimated volume of the discovery is in the range of 18 to 33 million bbls of recoverable oil.

“We are pleased with having proven new very high value resources in the Grane area,” Tore Løseth, vice president for exploration in the North Sea, said. “The oil discovery is located directly north of the Grane field and can be developed effectively.”

Timely near-field exploration is an important element in Statoil’s exploration strategy for the Norwegian continental shelf (NCS). This implies exploration close to existing installations that in the near future will have spare capacity for new tie-ins. “Near-field exploration is an important contribution in Statoil’s exploration portfolio on the NCS,” Mr Løseth said. “Even though volumes in these discoveries are moderate compared with the big finds over the last few years, these are fast, high-value barrels that are important for extending the production life of existing installations.”

In 2013, about 40% of Statoil’s exploration wells on the NCS will be near-field exploration. In addition to the Grane area, this includes the Oseberg, Fram/Gjøa and Tampen areas.

Exploration well 25/11-27 is situated in the Grane Unit in the North Sea. Statoil is operator with an interest of 36.66%. The partners are Petoro (28.94%), ExxonMobil Exploration & Production Norway (28.22%) and ConocoPhillips Skandinavia (6.17%).

In addition, BP has successfully secured support from the other working interest owners at Prudhoe Bay to begin evaluating an additional $3 billion worth of new development projects. These projects, located in the west end of the Greater Prudhoe Bay Area, could continue for approximately 10 years, further increasing the state’s oil production and providing additional jobs.

“With this new tax law, the Alaska legislature and Governor Parnell have taken an important step toward improving Alaska’s long-term economic future,” Janet Weiss, BP Alaska region president, said. “Our announcement today should make abundantly clear that BP is committed to being a part of that future and to continuing to extend the life of North America’s largest oil field.”

BP Exploration (Alaska) will issue a request for proposals this summer for the two additional rigs in Prudhoe Bay. The first drilling rig is expected to be in place by 2015 and the second in 2016. This will increase BP’s rig fleet in Alaska to nine. Meanwhile, BP expects to increase well work as soon Q4 2013, a move that should improve the performance of existing wells at the Prudhoe Bay and Milne Point fields.

The additional development opportunities being evaluated by working interest owners are in the west end of Prudhoe Bay and include expansion and de-bottlenecking of existing Prudhoe Bay facilities, constructing a new drilling pad, and expansions of existing pads, including the drilling of more than 110 new wells. The appraisal phase will take two to three years and will include engineering work and securing regulatory approvals for multiple development projects.

“Now that an improved tax structure is in place, oil and gas projects can once again move forward, keeping Alaska competitive in the midst of America’s recent energy renaissance,” Ms Weiss said.

BP is also working with other companies and the state of Alaska to commercialize Alaska North Slope natural gas as part of a joint concept selection group focused on a South Central Alaska LNG project.

The Karish discovery is the fifth discovered field with an estimated gross mean resource size over 1 Tcf. It is also the seventh consecutive field discovery for Noble Energy and its partners in the Levant Basin. With the addition of Karish and the recent increase in resource estimates at Tamar and Leviathan, total discovered gross mean resources in the Levant Basin are now estimated to be approximately 38 Tcf.

Ensco’s Ensco 5006 semisubmersible drilled the Karish well and will relocate to Cyprus, where it is scheduled to spud an appraisal well at the Cyprus A discovery next month.

Noble Energy is the operator of the Alon C license with a 47.06 percent interest. Co-owners are Avner Oil and Delek Drilling each with a 26.47 percent interest.

Schlumberger is focusing on addressing geological and reservoir challenges in the Gulf of Mexico that lead to narrow operating environments, Wallace Pescarini, vice president, deepwater operations at Schlumberger, said. “As you access the reservoir, drilling through the salt, in the pore and frac gradient, and in very narrow operations, the weight window adds challenges during the drilling process.”

By Joanne Liou, associate editor

Growing activity in the Gulf of Mexico (GOM) reflects the industry’s capability to meet increasing operational challenges in deepwater, where activity has returned to pre-moratorium levels despite more stringent regulations. Schlumberger, which relocated resources to other basins during the moratorium period, has moved resources back to the GOM as activity returned and is continuing focus on geological and reservoir challenges that lead to narrow operating environments.

“That is a challenge for the GOM, and some potential shallow hazards, such as shallow water flow or near-surface faults, add more complexity to the operation. As you access the reservoir, drilling through the salt, compounded by uncertainty on the pore and frac gradients and very narrow operation mud weight window, adds challenges during the drilling process,” Wallace Pescarini, vice president, deepwater operations, said.

To address such challenges, Schlumberger is combining real-time drilling evaluation data with the reservoir model using advanced interpretation techniques to analyze and act on the data in real time. Seismic-guided drilling is one example, in which the LWD checkshot data are used to constrain the surface seismic model in real time to help narrow down the depth uncertainty and to identify overpressure zones in front of the drill bit, Mr Pescarini said.

In the GOM, petrophysical and seismic data from offset wells are used to create a model of the formation pressures. “By leveraging the latest advances in computing power, we are now able to re-migrate the seismic model around the well while drilling,” he stated. “This allows us to predict the formation pressure up to 1,500 ft (457 meters) in front of the drill bit.” The drilling program can then be modified to reflect the real-time predictions.

Another trend that continues to evolve, mainly to respond to the described operational complexity, is the capability to bring drilling experts together as an integrated team during the planning and execution phases, supported by real-time workflows. “This is a trend you are seeing in the market. Specifically in the GOM, we are very well supplied with these experts and have located them in our PetroTechnical Engineering Centers to ensure that a collaborative environment is created.”

Andy Hawthorn, Schlumberger business development manager, earth model building, explained that there is a four-fold increase in deepwater NPT due to wellbore instability and mechanical instability, during a presentation at the company’s re-launch of its Digital Technology Theater in Houston in March.

The ultimate aim is to drill fewer wells but produce more oil. “To be successful, every well has to be in the right place and be able to produce over the entire life of the field,” Andy Hawthorn, Schlumberger business development manager, earth model building, said during a presentation at the company’s re-launch of its Digital Technology Theater in Houston in March. “Industry statistics show that with GOM wells in over 3,000-ft water depth, about 45% to 48% of all wells require a sidetrack. Of those, 50% require more than one sidetrack, which means we’re not getting it right the first time, all the time.”

Close collaboration among operators, contractors and service providers will be key going forward, as downhole nonproductive time (NPT) continues to increase, driven by the increasing geological complexity of deepwater E&P. “There is a four-fold increase in NPT due to wellbore instability and mechanical instability,” Mr Hawthorn said. “There is also a four-fold increase in the number of times BOPs are activated as the complexity of wells increases.”

Reducing NPT will require a combination of efficiencies within the drilling operation, coupled with putting wells in the right place the first time so it can produce over the entire life of the field. “You have to combine softwares and combine disciplines and expertise. You have to understand how much uncertainty you have in your measurement and the assumptions you made in your workflows before you hand it to the next set of people to do the next sequence of processing.”

For a project in the subsalt Wilcox structure in the GOM, Schlumberger generated 1,000 models of what the top Wilcox would look like. “This is the starting point because attempting to quantify on the amount of uncertainty allows you to make the correct measurements that drive the uncertainty down, allowing you to make objective decisions,” Mr Hawthorn explained. A simple one-dimensional stretch in most cases is no longer adequate. “We are dealing with a 3D, and increasingly, 4D environments. This requires a better approach.”

Digital Technology Theater

The Digital Technology Theater (DTT) in Houston is a key platform Schlumberger is using to help operators in the Gulf of Mexico. A re-launch event in March focused on showcasing the company’s deepwater technologies and services. The upgraded DTT features a 25-ft-wide screen powered by six high-resolution Barco projectors.

“With so many disparate groups and disciplines involved in deepwater projects, collaboration is absolutely fundamental to ensure that the project is carried out safely and successfully. The DTT is a good example of how the various groups can integrate and communicate,” Keith Tushingham, Schlumberger Information Solutions (SIS) DTT producer, said.

In April, the DTT was used to connect to the Schlumberger office in Aachen, Germany, to connect a client to the basin modeling experts. “Global tele-presence is common place today, but being able to transmit large amounts of data to remote locations is a different matter,” he said. “That requires good latency connectivity and cloud-based collaboration capabilities. This is the difference that the DTT brings to an organization”

Schlumberger will open another DTT in Kuala Lumpur in July to serve the Asia market, and other centers are planned for Oslo, London, Dubai and Calgary by the end of this year. Each center will address specific regional challenges.

“As SIS is focused on these industry challenges, it’s catalyzed a broader integration across our organization,” Mr Tushingham stated. “This allows us to integrate and get access to the breadth of all our expertise.”

By Joanne Liou, associate editor

Martin Craighead, president and CEO, Baker Hughes

In the not so distant past, with deepwater exploration still in its infancy, the fear of shrinking oil and gas supplies frequently ran high. Today, however, industry has embraced the challenges of deepwater and continues to push beyond to ultra-deepwater. “We live in a world where we now see a future field with energy prosperity,” Baker Hughes president and CEO Martin Craighead stated at the International Petroleum Technology Conference in Beijing in late March. “There are two primary drivers of this new prosperity: unconventionals and deepwater.”

Addressing the latter, Mr Craighead focused on ultra-deepwater, likening E&P in that frontier segment to reaching the moon. “Today, our customers are asking us to help them solve problems of the ultra-deep frontier, which is so much more challenging and exciting. It’s like going to Mars.”

Baker Hughes is working with 10 customers who collectively intend to drill approximately 300 deepwater wells over the next decade in the GOM, representing about $30 billion initially to extract resources from the Lower Tertiary, Mr Craighead explained. Technology breakthroughs associated with completions and sustained production from frontier targets, such as the Lower Tertiary and Jurassic formations, will be key to industry’s success. “Engineering excellence and innovation and outmost reliability here, I believe, will be potentially rewarded far greater than anywhere our industry has ever worked before.” According to a Baker Hughes customer, a 1% improvement in recovery on some projects can translate into an additional $3.2 billion, Mr Craighead stated.

With approximately 45 active rigs, 11 of which entered the region over the past year, the GOM remains the fastest-growing deepwater market in the world, he said. “An additional three or four will be commissioned this year, and moving from traditional deepwater to the ultra-deep frontier holds both great challenges, as well as great potential prosperity, if those challenges can be met.”

The formations are consolidated, and with reservoir pressures exceeding 30,000 psi and temperatures ranging from 350°F to 400°F, large stimulation treatments will be required to establish reservoir productivity. “In fact, stimulations in the Lower Tertiary projects must be carried out across multiple zones; some particular cases covering as much as 3,000 ft of vertical reservoir,” Mr Craighead said. “In addition, each zone will require up to half a million pounds of proppants.”

Further, the wells face a high risk of unwanted solids, which can damage completion systems, compromising its reliability. “Every component in these systems must be designed to a whole new level of reliability,” Mr Craighead said. Operators are requiring fully redundant subsea and well boosting systems, for example, with a life expectancy in excess of 10 years, he added.

Electrical submersible pumps (ESPs) have been operating reliably in deepwater environments for years, but the next frontier will require these ESPs to run in HPHT conditions and sit idle for as long as five years before activation. “Once it’s turned on, it better work and work for a long time,” Mr Craighead said.

The ESP system must be fully compatible with the well completion hardware, which will have its own set of complexities in the ultra-deepwater environment. “The laws of physics are forcing us to re-engineer highly complex systems that have typically been designed for the dry environment. Each component of these innovative intelligent production systems must be waterproof like never before and designed to withstand the pressures that come with 10,000 ft of water.”

Well depths and operating conditions will also challenge fiber-optic technology. To connect upper and lower completions and provide continuous automation downhole, two fiber-optic streams must precisely align – each thinner than a strand of hair – and maintain the photon productivity over the entire length of the wellbore, Mr Craighead explained. “The price at stake in this new frontier, nevertheless, is enormous.”

By J.W. Jenner, A. Morrison, Rockhopper Exploration; R. Lyons, Desire Petroleum; L. Phillips, AGR Petroleum Services; I. McBean, Diamond Offshore Drilling (UK)

Figure 1 shows the structural configuration of the North Falkland Basin’s Sea Lion area, where the Sea Lion 14/10-2 exploration well was drilled in 2010. Extensive 2D seismic surveys were conducted by the operators after obtaining licenses and in preparation for the drilling campaign.

Offshore the Falkland Islands, approximately 650 km southeast of the South American continent, two small UK operators with limited in-house operational resources conducted a successful drilling campaign. The project was made possible through teamwork and the continuity provided by using a drilling project management company and a single drilling contractor.

This article will summarize the geological conditions encountered in the North Falklands Basin and discuss the drilling engineering and well planning. It will also discuss the importance of the logistics planning and supply chain management, which included the enhancement of limited onshore support facilities in Port Stanley, the main population center, and the introduction of industry standard safe operating procedures.

The area discussed in this article is referred to as the North Falklands Basin (NFB). Water depth across the basin varies from 100 meters in the south to 500 meters in the north. Most wells have been drilled in water depths between 200-500 meters. Metocean conditions are similar to the Santos Basin offshore Brazil and generally more benign than the UK Central North Sea.

It had been acknowledged for some time that the NFB is a significant petroliferous basin, but its remoteness had deterred any extensive exploration activities. In the mid-1990s, a licensing scheme similar to that in the UK North Sea was introduced by the Falkland Islands Government (FIG). Four major oil companies were awarded blocks north of the islands and, after conducting extensive seismic surveys, decided to jointly contract a rig to drill six exploration wells in 1998.

Oil and gas were encountered in five of the six wells drilled; however, the volumes did not maintain interest, and the licenses were dropped.

In 2004, when the licenses became available again, Desire Petroleum and Rockhopper Exploration applied for blocks in the NFB and conducted 2D and 3D seismic surveys. By 2008, interpretation of the survey data along with previously acquired data revealed a number of structures potentially containing billions of barrels of recoverable hydrocarbons.

At the time, however, there was a shortage of available semisubmersibles with 1,000-meter water depth capacity. There was also little interest from drilling contractors for a short-duration exploration drilling program in a remote location.

In August 2009, Desire Petroleum signed a Letter of Intent for Diamond Offshore’s Ocean Guardian semi. The initial contract provided for four firm wells, plus four priced options.

Table 1: At the beginning of the Falkland Islands drilling campaign when Diamond Offshore mobilized the Ocean Guardian semi, there were prospects for only four wells. Just two years later, the rig had completed an evolving and significantly expanded program of exploration and appraisal wells.

The NFB is a north-south trending Atlantic rift filled primarily by Early Cretaceous lacustrine organic claystones and shales interspersed with sandstones that are primarily lacustrine turbidites, approximately 130 million years old. The basin, approximately 300 km by 50 km, is high-relief and structurally simple, with a deep graben bounded by shallow basement highs.

The oblique lineations become more pronounced toward the Falkland Islands coast, where Paleozoic rocks come to surface. A shallow anticlinal axis runs north-south along the center of the basin, and this axis, a relatively late-stage structural inversion, was drilled in two places by Shell in 1998. The Barremian turbidite fan systems that form the main hydrocarbon reservoirs discovered so far are sourced from the Paleozoic and older basement rocks of the eastern basin flank. The sands were initially deposited on the shallow basement highs, where they were winnowed, sorted and cleaned before being transported under high energy turbidite flows into the freshwater lake system in the basin. The reservoir sands, which were cleaned and sorted before being deposited within the contiguous organic source rocks and sealing shales that envelope the sands, are clean, uncemented, well sorted and free from clays within the pore spaces. The Sea Lion 14/10-2 exploration well drilled in 2010 was the first test of this play type in the NFB (Figure 1).

Figure 2: A generic well design was developed for the North Falkland Basin wells based on information from a previous drilling campaign. The design incorporated a 36-in. surface hole to approximately 164 ft (50 meters) below the seabed, where a 30-in. (76-cm) conductor with a 20-in. (51-cm) casing shoe would be run and cemented.

Desire had contracted AGR Petroleum Services to provide project management services covering permitting, well planning, engineering and programming, on-site supervision, logistics management and support and financial forecasts and well cost tracking on a daily basis.

The Ocean Guardian readied for departure on 26 November 2009. At the same time, AGR was setting up an office in Port Stanley and working with local companies to build a supply base near the harbor with storage facilities for casing, wellheads, mud, cement and other drilling consumables. An operations office was established with satellite communications with the rig and Aberdeen to manage the operation.

In December 2009, Rockhopper Exploration joined Desire Petroleum with an assigned contract for the Ocean Guardian to drill two additional exploration wells. The initial program was for the rig to drill up to six firm wells in the NFB for Desire and Rockhopper.

AGR then developed a generic well design, and sufficient consumables for four wells were ordered. This together with rental tools and excess rig equipment was transported via two large coaster vessels from Aberdeen to the South Atlantic. The three-week voyage was timed so the equipment would arrive well in advance of the rig.

Marine support was provided by two anchor-handling supply vessels (AHSV). An additional large platform supply vessel sailed independently from Aberdeen carrying extra high-value rental equipment and spud equipment for the first well; they were to be unloaded directly onto the rig in case of any delays in discharging the first coaster. Both AHSVs were equipped with a fast rescue craft and emergency life-saving equipment as it was planned at least one would be at the rig acting as standby vessel while drilling or either could be used for crew change if needed.

For routine crew change and offshore support, a dedicated S61N helicopter was contracted from a company that was already operating similar machines in the islands in support of the military. The rig crew and service company personnel would be working a 28/28 day shift cycle, and an arrangement was made to use excess capacity on the twice weekly military passenger charter flights from the UK to transport these personnel to and from the islands.

Midway through the two-year campaign, the demand to efficiently move personnel between the UK and the Falkland Islands on a regular basis had increased significantly. The companies then set up a fortnightly dedicated charter flight and replaced the S61N helicopter with two Super Puma AS332L aircrafts that were more modern and had greater range and capacity. The units were mobilized from Europe to a dedicated operating base at Stanley Airport.

Throughout the two-year campaign, emphasis was placed on minimizing any disruption to crew changes. This resulted in a low turnover rate in rig personnel.

In the lead up to the arrival of the Ocean Guardian and start of drilling operations, senior executives from both Desire and Rockhopper visited Stanley on a regular basis to provide progress updates to the Falkland Islands government and the Department of Mineral Resources (DMR).

Further, public “town hall” meetings were held to keep the islands’ residents informed and to answer any questions about how the drilling campaign might affect them or the local environment. Rockhopper also placed an industry veteran in Stanley to liaise between the company and local authorities and local community.

Legislation relating to offshore drilling activity in the NFB is the responsibility of the Falkland Islands DMR. Wells-related programs, environmental assessments, oil spill plans and permits to locate and drill were submitted to the DMR, which in turn referred them to various UK agencies for review before issuing approvals. Environmental Impact Assessments, which had been carried out for the earlier seismic surveys, were revisited and upgraded prior to the start of the exploration drilling program.

An oil spill contingency plan (OSCP) was also put in place by the individual operators.

Figure 3a : A pipe yard and equipment storage and maintenance area was constructed west of Port Stanley.

A generic well design was initially developed based on information available from the previous drilling campaign. No major drilling problems had been encountered and, with an expected total depth of less than 3,000 meters, a North Sea-type exploration well design was adopted (Figure 2). This incorporated a 36-in. surface hole to approximately 50 meters below the seabed, into which a 30-in. conductor with a 20-in. casing shoe was to be run and cemented.

Figure 3b: All the cargo and fishing vessels calling at the islands used a floating interim port and storage system.

Shallow gas had not been previously encountered, and the 3D seismic survey over the area showed no indication of its presence. The formations to be drilled were expected to be mainly claystones with occasional limestone stringers, which showed as good reflectors on the seismic profile, and sandstone intervals increasing with depth. With returns to the seabed, the 17-½-in. hole would be drilled riserless to approximately 1,200-meter TVD, where there was a good seismic reflector and the casing point selected on penetration rate.

After running and cementing the 13 ^3/8-in. casing and 18 ¾-in. wellhead, the BOP and riser would be run before drilling a 12-¼-in. hole to just above the projected reservoir at approximately 2,200 meters and setting 9 ^5/8-in. casing. An 8-½-in. hole would be drilled through the reservoir section to TD at approximately 2,700 to 2,850 meters. Leak-off tests would be carried out after drilling out each casing shoe to determine the kick tolerance and ensure well integrity.

While drilling with no returns, bentonite sweeps would be used to clean the borehole. With the riser in place and full circulation established, an Ultradril premium water-based mud system would be used. From the earlier wells, it was determined there were no serious drilling hazards, although caving of loose sands, washouts, lost circulation and some tight hole had been experienced. The team decided that those hazards could be controlled via good drilling practice and the water-based mud system.

Drilling motors and MWD/LWD tools would also be run in the drill string to improve performance and provide continuous gamma-ray and resistivity logs and directional data.

There was no evidence of abnormal or overpressured formations in the prospects to be drilled. Pore pressure studies had been carried out in Desire’s license area immediately south of the Rockhopper blocks using MDT/FMT and leak-off data from the wells drilled in 1998. This was augmented by a burial history and basin modeling study, which concluded that there may have been 1,000 meters of late inversion uplift across the previously drilled area but confirmed there was no evidence from existing data of overpressure in the depocenter in the Desire license area.

As the proposed wells in the Desire acreage were to be deeper than those in the Rockhopper area, it was concluded that overpressure across the basin was not expected.

The operators committed to gather as much wellbore data as economically possible because revisiting the area with a rig may not be possible in the short term. Besides the use of MWD/LWD tools in the drill string as previously mentioned, the operators also used regular open-hole wireline logging tools – gamma ray, resistivity, calliper, density, neutron, including SP in the 12 ¼-in. and 8 ½-in. open-hole and side-wall cores and seismic profilers at TD if required. In the event of success, formation pressures and samples could be taken in the reservoir.

A decision had been made not to send rotary coring and well-testing equipment to the islands due to cost factors. Suppliers also were reluctant to commit this relatively scarce equipment during a period of high demand in the North Sea.

To complement the well data that had been obtained, a data repository system was used to provide a secure off-site electronic records and data storage service. All well-related reports, logs and logistics data would be transmitted daily to this facility, minimizing recordkeeping. This was supplemented by real-time drilling and well data transmission services that enabled supervisors in Stanley, management personnel in Aberdeen and operators senior staff to monitor progress. The system recorded and transmitted a full range of well data, including drilling parameters, mud logging and MWD/LWD, providing continuously updated screens.

Shortly after the Letter of Intent for the rig was signed, personnel from Desire and AGR moved to Port Stanley to set up a shore base to provide logistics and operational support for the drilling of up to four wells. This was soon extended to eight wells by Rockhopper’s agreement to participate in the rig contract.

Because there were no suitable facilities in place, a pipe yard and equipment storage and maintenance area (Figure 3a) was constructed to the west of Stanley by a local logistics company, which also provided the handling equipment and personnel. The base would provide easy access to the main commercial jetty, the floating interim port and storage system (Figure 3b), a floating structure used by all cargo and fishing vessels calling at the islands.

By the time the rig arrived in mid-February 2010, the operations office and base were fully functional. With the arrival of the coasters from Aberdeen and discharge of the first consignments of well consumables, the supply chain was also established.

Local personnel were employed at the base when possible, but due to their lack of experience in handling oilfield equipment, experienced personnel were initially contracted from Aberdeen.

Figure 4: After a first round of wells were drilled by Desire and Rockhopper in the NFB, the well design was revised. Hole conditions and leak-off tests were good enough to continue drilling the 12 ¼-in. hole to TD after setting 13 3/8-in. casing.

The Ocean Guardian arrived on its first location north of the Falkland Islands on 19 February 2010. The local operations office was being manned by the drilling superintendent, drilling engineer and logistics supervisor. All were AGR personnel, with additional support from the Diamond rig manager and logistics controller. AGR also provided the day and night drilling supervisors and logistics coordinator on the rig.

This team remained relatively constant throughout the drilling campaign, ensuring continuity of personnel from well to well and the same operating standards and procedures.

A daily conference call hosted by the AGR well team leader in Aberdeen was instituted once the rig was on location. Participants included the senior rig-based personnel – OIM, senior drilling supervisor, toolpusher, logistics coordinator and safety officer – the team in Stanley and Aberdeen-based personnel. Operator staff were encouraged to participate and contribute when necessary.

Drilling started on the Desire 14/19-1 “Liz” exploration well on 22 February 2010. Despite information from pore pressure studies, some time was lost to unprognosed formation overpressure and to control a gas kick. The team completed and abandoned the first and deepest well in the program in about 53 days.

The rig then moved to the “Sea Lion” 14/10-2 location and spudded the first well to be drilled by Rockhopper on 16 April 2010. Following the standard design, the well was drilled virtually trouble-free to a TD of 2,744 meters in 18 days from spud, making what was eventually judged to be a commercial oil discovery. This was an unusual achievement for a company’s first ever well.

As drilling progressed toward the potential reservoir, the real-time data system proved invaluable, recording increasing gas levels in the mud returns and alerting the rig geologist and Rockhopper personnel in the UK to the situation. It was possible to remotely monitor what was happening as the sands were penetrated and the extent of the hydrocarbon column was revealed, enabling the rig geologist and the UK-based exploration manager to make timely and informed decisions regarding the well TD and to set up the wireline logging program. At TD, a full suite of wireline logs was run, side-wall cores were taken and reservoir fluid samples collected before conducting a final VSP survey.

Having confirmed that a considerable oil column had been penetrated, a well test was necessary to determine the nature of the fluids and potential productivity of the reservoir. As noted earlier, no testing equipment had been mobilized, and it would be at least three months before it could be shipped to the Falkland Islands.

Throughout the two-year drilling program, the operators experienced approximately 9.4% NPT and 5.8% waiting on weather averages. Figure 5a (above) charts the time versus depth for all wells in the Sea Lion, and Figure 5b(below) charts time versus depth for all exploration wells in the campaign except Sea Lion wells.

A 7-in. liner was run across the reservoir, and it was suspended for later re-entry and test. The total time from spud to move off location was 32 days. The rig was moved south of the islands to drill a well for a third operator before returning to the NFB to drill the Rockhopper Ernest 26/6-1 exploration well.

This interval provided sufficient time to mobilize the basic test equipment, prepare the testing program and get the necessary approvals.

Following the re-entry and testing of the Sea Lion discovery well, a sequence of Desire exploration wells was drilled, including one sidetrack, completing the first period of the rig contract.

With the success of the Sea Lion discovery well, Rockhopper and Desire jointly contracted a two-vessel 3D seismic program to cover the area around the discovery and fill in gaps in the existing seismic data. The survey south of the Sea Lion discovery later revealed the southerly extent of the structure and whether it stretched into the Desire 14/15 license block. The companies decided to fast-track interpretation of the new data to determine the best locations for the program of appraisal wells.

They extended the rig contract, allowing Desire to drill one more exploration well and Rockhopper to carry out an eight-well appraisal drilling program that included a more detailed test on one of the wells. The project terminated in early 2012, with the drilling of the 14/15-4 appraisal well by Rockhopper that proved the southern extension of the Sea Lion sands into the Desire 14/15 license block and revealed additional sand bodies containing hydrocarbons.

On completion of the well, the rig was released and returned to the North Sea after drilling 15 wells, including four sidetracks, and carrying out two well tests.

With experience from the first wells, appraisal well designs were modified. After setting 13 ^3/8-in. casing, hole conditions and leak-off tests were good enough to continue drilling 12 ¼-in. hole to TD. (Figure 4). In the later wells, the extent of prospective pay zones was identified by first drilling vertically to TD and logging before plugging back and sidetracking to take cores across the reservoir interval.

There were very little nonproductive time (NPT) or waiting on weather (WOW), with averages of 9.4% and 5.8%, respectively, throughout the two-year drilling campaign (Figures 5a and 5b). NPT was mainly attributed to wellhead problems, one stuck casing event and the loss of rig power on one occasion. Most WOW was attributed to weather interrupting running or pulling the BOP stack and riser or delaying anchor handling when moving location. BOP and riser handling were affected both by rough seas and by flat calm conditions, which were generally accompanied by thick fog that prevented the standby vessel from approaching the rig.

When the extent of the Sea Lion discovery well was realized, steps were taken to enable the well to be tested. A standard North Sea subsea testing package and tubing string were assembled and shipped from Aberdeen to arrive on location before the end of the Rockhopper Ernest exploration well, a window of approximately three months. Well test planning meetings were convened to discuss the test and the information to be gathered. These meetings were attended by reservoir engineering and well test consultants, Rockhopper operations advisers and AGR testing engineers, who would compile the detailed well test program and procedures.

The reservoir samples recovered from the discovery well revealed that the crude oil was waxy and had a pour point around 68˚C. This had the potential to create problems in the low ambient temperature environment surrounding the riser and wellhead, where the water temperature at the seabed had been measured at 4˚C, and for some distance below the wellhead. An interruption of flow during the test would result in a tubing string plugged with solidified waxy crude oil.

To counter this eventuality, a restricted test procedure was evolved that would provide the minimum reservoir data required with a short flow period, sufficient to bring reservoir fluids to surface under controlled conditions. Provision was also made for solvent chemicals to be injected into the subsea test tree within the BOP stack if necessary. The basic nature of the testing string made chemical injection anywhere below the tree impossible.

The rig moved back onto the 14/10-2 location in September 2010 and re-entered and cleaned out the suspended discovery well. From the logging data, there appeared to be two separate zones in the reservoir with slightly different pressure gradients (Figure 6). However, because of the restrictions posed by the testing equipment, it was only possible to carry out one test, combining flow from both zones and the tubing-conveyed perforating guns on the test string were spaced out accordingly. After the test string had been set and the perforating guns activated, a 300-bbl cushion of diesel oil was injected into the formation and shut in to heat up over a period of 12 hours before being back-flowed to stimulate the well at the start of the test.

A successful but limited test was carried out with sufficient flow to surface to measure the well parameters needed and collect samples of reservoir crude oil and gas. As soon as the flow was stopped, the contents of the tubing were reversed out to avoid any build-up of wax, and the well was killed.

When the test string was recovered, it revealed that the perforating guns across the lower zone had not fired and all the flow (approximately 2,000 bbl/day) had come from the upper zone. On completion of the test, the well was plugged and abandoned.

In June 2011, a second well test was carried out on the 14/10-5 Sea Lion appraisal well. To make it as comprehensive and representative as possible of production conditions, a fully engineered test package was assembled to mitigate the combined effects of the waxy crude oil and low ambient temperatures. By using an electric submersible pump set approximately 200 meters above the 7-in. liner top on a combination 5 ½-in. by 4 ½-in./4 ½-in. by 3 ½-in. vacuum-insulated tubing string, heat loss could be minimized and the test period safely extended.

The surface equipment was also upgraded and trace heating of pipework installed from the rig floor to the test equipment to help maintain flow. The test was successful, yielding a flow rate of 5,500 bbl/day under controlled conditions and approximately 9,000 bbl/day under open flow and maximum pump rate. On completion of the test, the well was abandoned and the testing spread returned to Aberdeen. Reservoir data was successfully acquired from the subsequent appraisal wells by the more economic combination of extensive coring in the reservoir and mini open-hole drill stem tests using the MDT dual packer wireline testing tool.

In the drilling program prepared for every NFB well was a statement that the principle objective was “to design, drill and evaluate the well to ensure zero LTAs and zero spills or releases during the well construction process.” With the operation being located in a remote area, attention to safety was critical. To ensure a consistent approach to operational safety when conducting a drilling program for two operators and switching between them while using the same personnel, a safety management system was adopted that ensured continuity of responsibility.

During drilling operations:

• The Diamond Offshore Drilling safety management system was followed when controlling activities on the drilling rig;

• The AGR management system was used to control preparation of the drilling and testing programs and to manage supervision of the work both onshore and offshore; and

• Diamond Offshore Drilling implemented the safety case for the Ocean Guardian as accepted and approved by the UK Health and Safety Executive.

In addition, AGR developed a management system interface document (MSID) to clarify the relationship between the operator (Desire or Rockhopper), the drilling contractor (Diamond Offshore) and the project management company (AGR) during drilling operations in the NFB. The MSID was agreed on and authorized by all parties and

• Set out and agreed environmental, health and safety arrangements to be applied during NFB offshore drilling operations;

• Ensured management and communication channels (both offshore and onshore) were established;

• Identified arrangements for emergency response;

• Identified how changes to procedures or work would be controlled under management of change; and

• Ensured full compliance with all statutory requirements was understood and followed.

During the drilling campaign, the Diamond Offshore well control manual was the primary source for well control issues other than where exceptions were specifically mentioned within the MSID.

The drilling contractor, with full support from the two operating companies and AGR, achieved a highly creditable record and standard of safety. This included an effective safety card system that encouraged all members of the crew to recognize both good and bad safety practices. By the end of the operation, some 7,748 cards had been submitted; 5,037 desirable and 2,711 undesirable, which promoted changes to working procedures and improvements to safety equipment. This resulted in only one lost-time incident (LTI) and one restricted day case throughout the campaign.

At the onshore supply base, an industry standard safety culture was introduced and training implemented for personnel with no oil industry experience. During more than two years of operations involving 822,159 manhours worked, only 107 incidents were recorded with two LTIs.

Figure 6: Logging data from Sea Lion 14/10-2 showed two separate zones in the reservoir with different pressure gradients.

When the Ocean Guardian departed Invergordon for the South Atlantic, it did so with the prospect of less than a year’s work, drilling only four wells for one operator. By the time it arrived on its first location, a second operator had joined the program, and two wells had been added to the schedule. Just over two years later, it returned north having successfully completed an evolving program of exploration and appraisal wells, including two unique well tests. This was made possible by the project management model adopted by the operators.

Neither Desire nor Rockhopper employed significant staff, particularly those with experience in offshore drilling or exploration drilling operations. Instead, they relied on a drilling project management company to provide the services normally associated with the in-house drilling, logistics, contracts, purchasing and well accounting departments of a major oil company. This service has evolved to meet the requirements of small exploration companies that have emerged in the industry. Common contracts for services and for the rig were also agreed by the operators, which allowed responsibility to pass seamlessly between them from well to well.

The relatively benign subsurface drilling conditions across the NFB also allowed a similar well design to be adopted for all wells, simplifying the supply and stocking of well consumables. Although the supply chain stretched back to Aberdeen, this posed no problems as consumable materials and service company equipment could be sourced and checked before shipment to Stanley.

Although it may have been possible to source some materials closer to the NFB, long-term rentals and bulk shipments from Europe were deemed to be cost effective and more reliable.

With modern communication systems, contact among the rig, the operations base and the management centers in the UK was easily maintained with continuous and up-to-date well data from the rig. However, despite this ease of contact, the previously agreed lines of communication established under the AGR management system were maintained throughout the campaign.

The similarity of legislation at the Falkland Islands with that of the UK also helped but could not be taken for granted. Maintaining local contact ensured that local requirements were understood. Having a Rockhopper representative in Stanley proved effective.

The successful two-year drilling campaign in the South Atlantic demonstrated the viability of conducting a remote operation without the necessity of setting up a large-scale local base or of locating large numbers of support personnel in the area. The model developed in this case was fit for purpose and could be repeated in the future.

SPE/IADC 163415, “Exploration and Appraisal Drilling Operations in the South Atlantic,” was presented at the 2013 SPE/IADC Drilling Conference and Exhibition, 5-7 March, Amsterdam.

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