Shell World Online

Delving deeper: unlocking offshore energy

Technology is helping oil companies like Shell respond to rising energy demand and concern over energy security by unlocking previously unreachable deep-water oil and gas deposits from the Gulf of Mexico to West Africa.

September 7, 2007
by JAMES SCHOFIELD

Standing on a deck larger than a soccer pitch, almost 30 metres (90 feet) above clear waters teeming with fish, it’s hard to believe the Ursa deep-water oil platform is floating. There’s not a hint of movement, allowing the giant structure weighing more than 57,000 tonnes – almost six times as much as the Eiffel Tower – to safely extract oil and gas from the dark, cold depths over a thousand metres below.

Moored south-east of New Orleans, Ursa operates in water almost 1,160 metres (3,800 feet) deep, the equivalent of three Empire State Buildings stacked on top of each other. The onboard drilling rig can reach more than four kilometres (2.5 miles) below the seabed, grinding through thick layers of salt, rock and densely packed sand to hit targets just a few metres across.

The Ursa platform shows the extraordinary efforts that oil companies are making to prolong production in the Gulf of Mexico, where reservoirs in shallower water are in decline. It also demonstrates one way that technology is helping oil companies respond to rising demand and concern over energy security: by unlocking previously unreachable deep-water oil and gas deposits everywhere from the Gulf to West Africa and Brazil.

The lure of the deep is clear. Global reserves in deep water – generally meaning depths of more than about 450-500 metres (about 1,500-1,650 feet) – are estimated at some 60 billion barrels of oil equivalent, enough to supply the USA for about a decade at current demand levels. That’s a tantalising prospect for companies eager to replace the oil and gas they are pumping at a time when easier opportunities both offshore and on are becoming scarcer.

But working in such difficult locations requires companies to overcome a number of tough technical challenges. Some of the most difficult are finding new ways to build these vast floating factories that can venture into ever-greater depths, designing new equipment to work in the intense cold and crushing pressure of water thousands of metres deep, and finding profitable ways to tap reservoirs scattered across many miles. And they have to do all this while keeping costs under control.

Bigger, deeper... lighter

In mid-May, Ursa is already wrapped in a blanket of suffocating humidity typical during the sweltering summer months of hurricane season in the Gulf of Mexico, when platforms up and down the coast can be battered by fierce storms. She’s one of a breed of platform that has been instrumental over the last decade in allowing companies to probe further in deep water.

Unlike earlier rigid structures that stood firmly on the sea floor, platforms like Ursa float on the surface, getting buoyancy from four giant vertical steel cylinders. The platform is secured to the seabed at four corners by 16 immense steel tendons – tension legs – each weighing almost 900 tonnes, which eliminate virtually any vertical movement. This allows the platform to remain stable while supporting thousands of tonnes of equipment.

Every day, Ursa produces enough oil to fill half a million cars and enough natural gas to power more than three million homes. On the production deck the heavy machinery that brings oil and gas to the surface and separates it creates a deafening whir. Workers in hard hats wear plugs to protect their ears. The living quarters above the production deck are home to the 120-strong crew, while the tendons and the pipes that bring oil and gas up from wells on the seabed disappear into the dark abyss below.

But there’s a limit to how much weight even this giant structure can bear and remain floating. As a platform moves further out in deep water, it needs longer steel tendons to secure it to the floor and longer pipes that reach down to the wells. These add extra weight and eventually the load would become too much.

So, as projects have become increasingly ambitious – today’s are now pushing into waters 3,000 metres (about 9,800 feet) deep and more – the industry has gradually turned to a different type of structure called a spar to tap oil deposits out of range of tension leg platforms like Ursa. Spars are not new, but until recent years they were used mainly to store oil close to offshore fields, rather than as full production platforms. They also float on the surface, but are buoyed by a single central cylinder that extends about 200 metres (660 feet) under the surface. Solid ballast – typically iron ore – at the bottom of the cylinder prevents tilting and provides enough stability for drilling and extracting oil and gas. Mooring lines hold the spar in place.

The tremendous length of such cylinders means their draft is too deep for the relatively shallow water of most shipyards. So the spar’s decks and equipment must be added in open seas by enormous, ship-mounted cranes. Only a few of these exist in the world and must be booked up to three years in advance. This pushes up costs and raises project risks – if the construction schedule slips, or the weather is too stormy to begin work, costs just keep on rising. Nevertheless, the added reach a spar offers is enough to overcome such drawbacks.

One of Shell’s next big offshore projects – Perdido – will use the spar design in the ultra-deep water of the Alaminos Canyon in the Gulf of Mexico, 320 kilometres (200 miles) south of Freeport, Texas. Operating in almost 2.5 kilometres (1.5 miles) of water, the spar will be the deepest spar production facility in the world, able to produce up to 100,000 barrels of oil and 200,000 cubic feet of gas a day. Due to come online around the turn of the decade, it will open up an area of ultra-deep water in the western gulf thought to contain reserves of between three and 15 billion barrels of oil equivalent, according to the magazine Petroleum Economist.

Keeping costs down is key in any project of course, but as tomorrow’s projects grow in scale and complexity it is becoming increasingly important. Drilling rigs can cost up to $600,000 a day to lease at current rates, while a single well can take 60 days to drill. With at least 19 wells, Perdido might have proven too costly to develop. “Weight and time cost money in deep water,” says Bill Henry, Perdido’s project venture manager. “It can make or break a project.” That has forced Shell to find new ways of building the platform.

One solution is to construct the hull and decks as a single piece instead of as separate modules that are then welded together. This will reduce the amount of steel needed, as well as the construction time. The spar will also include a fully integrated drilling rig. Despite adding millions of dollars to the spar’s price tag, it will save money over time by eliminating the need to lease a more expensive mobile offshore drilling rig at today’s high prices. Having the rig will also make it easier and quicker to maintain the wells from the platform.

Crushing pressure

Whatever structure is used on the surface, the dark depths of today’s deep-water projects – among the lowest points on the planet so far explored by man – present another set of crucial challenges. In these pitch-dark surroundings robotic submarines, operated remotely from the surface, are indispensable. About the size of a car, they carry lights and cameras, sharing the icy environment with rarely seen species of fish while conducting the intricate work of installing the complex infrastructure of wells, pumps and pipes on the sea floor.

The weight of thousands of metres of water bearing down exerts extreme pressure on equipment – up to 5,000 pounds per square inch, which is almost 350 times the average air pressure at sea level. That’s enough to crush conventional equipment, so the industry uses special equipment made from extra-thick metal to withstand the pressure. But this means it is extremely heavy, adding to the difficulty of installation. And in the case of the pipes leading to the surface, the extra weight burdens the platform above, limiting how deep it can operate.

To overcome this, Shell and others in the industry are now developing ways to adapt carbon fibre and other strong, lightweight composite materials already used in other industries such as aerospace. These new, lighter materials, needed for the next generation of projects in ultra-deep water, are likely to be deployed around the turn of the decade.

Keeping the oil flowing this far down is a struggle too. Near-freezing temperatures on the seabed, combined with high pressure, cause it to congeal. Gas and water mingled with oil form ice-like hydrates. Both these effects can block pipes. Companies solve this problem in a number of ways. Adding chemicals to prevent freezing is one traditionally used across the industry. More recently, Shell has taken inspiration from marine life to develop new chemicals based on fish protein to do the job better and more cheaply. Injected into the oil and gas as they are extracted, the additives can be used in far lower doses than the older generation of chemicals and have already saved the company millions of dollars in projects in the Gulf of Mexico.

Pipe-in-pipe heating for the lines that carry the oil and gas to the surface is another solution. Oil and gas flow through a heated inner pipe, keeping them fluid. They are insulated from the freezing water by an outer pipe.

Even when it flows freely, lifting the oil and the gas over two kilometres (1.2 miles) from the ocean floor to the surface requires enormous effort. For instance, Perdido’s reservoirs simply don’t have enough natural pressure to push the oil and gas to the surface on their own. So powerful pumps with more horsepower than Formula 1 racing cars will provide the necessary artificial lift. They will also reduce the backpressure on the well – generated by the weight of thousands of metres of water – that would shorten its production life. “The pumps are absolutely critical,” says Bill Henry. “Without them the well would ultimately die much earlier.”

Scattered fields

Geology itself provides still more obstacles that deep-water projects have to surmount. While companies always try to pick off the choicest, large reservoirs first, many of today’s remaining reserves, both in shallow and deep water, are found in small, separated deposits, rather than single large ones. This means more wells, tens of kilometres apart. If a separate platform were used for each, they would be impossibly expensive to develop. To turn a profit, the fields must be connected together centrally using a single platform. So the industry has developed a new system that allows a number of wells to be drilled, the oil and gas extracted and maintenance to be carried out all on the sea floor - and all of that from the same platform.

Perdido, for example, will cluster at least 19 separate wells directly below the spar. Below the sea floor, horizontal drilling will then zero in on deposits of oil and gas that are scattered up to 50 kilometres (30 miles) apart. Clustering the wells eliminates the need to move a rig large distances to maintain each well. Instead, winches attached to the mooring lines will slowly position the enormous bulk of the spar above any one of them in a radius of 45 metres (150 feet), giving the rig direct access to carry out repairs and routine maintenance.

Another advantage of clustering is that fewer pumps and heavy pipes are needed to carry the oil and gas to the surface, saving money and reducing the strain of weight on the spar above. In the past each individual well, spaced kilometres apart, would need a separate pipe to transport the oil back to the platform. Instead at Perdido they will feed into a central hub beneath the spar on the sea floor, and five pipes will carry the oil and gas to the platform. The result is a production facility operating at twice the depth of the Ursa platform and producing from many more wells in a cost-effective way.

But linking together different reservoirs across a wide area throws up other snags. Oil from different reservoirs can vary, being heavier in one than another, or having higher concentrations of sulphur, water and other impurities like sand. The natural pressure in separate reservoirs can also vary. And the rock formations through which wells need to be drilled can change from place to place. All these factors affect how a well needs to be drilled and the oil and gas extracted – meaning a one-size solution won’t fit all.

Shell’s Parque de Conchas project, under development 120 kilometres (75 miles) off the coast of Brazil, has been designed to address these challenges. It will link together 21 wells across four different fields with a range of different reservoir pressures, gas content and oil characteristics. For these wells, pumps will be needed to overcome the low pressure of the fields and lift the oil and gas from depths between 1,600-2,000 metres (about 5,250-6,550 feet). Depending on the gas, water and impurity content of the oil from each well, the development will use machines to separate the oil and gas on the sea floor. And because the oil from a number of wells will be combined before being separated and pumped, fewer pipes, each larger in diameter than normal, will help lift the oil to the surface. These will be fitted with small buoys to reduce weight on the platform above, enabling their use in ultra-deep water.

Little respite

New world records for the depth of offshore projects continue to be set on a regular basis as oil companies explore ever further into this hostile environment, driven by the need to find and extract scarcer resources.

This push into the deep is likely to accelerate. Production in most of today’s deep-water projects is expected to peak by 2012, driving a second and third wave of exploration into more remote and fragmented reservoirs and stimulating the technological advances to make it possible. To prepare for that, companies are working on a range of innovations.

Over the last decade, for example, Shell has developed a new way to transport oil and gas from remote deep-water wells without the need to heat it. Instead of preventing solids forming, chemicals encourage water crystals to form and wax to separate out, while keeping the oil and gas flowing. The resulting slurry of oil, gas and solids can be piped back to the platform – up to a 160 kilometres (100 miles) if necessary. Expected to be ready for use around the turn of the decade, this cold-flow technology will use fewer chemicals and eliminate the need for electricity.

Another focus of research is how to place as much equipment on the sea floor as possible to reduce or eliminate the need for production platforms. For example, at Ormen Lange, a joint project in which Shell is a partner to develop a gas field off the Norwegian coast, project engineers are investigating ways to install compressors on the sea floor to provide the pressure necessary to transport the gas to shore. If successful, that would eliminate the need to use an offshore platform that will otherwise be required when the natural pressure in the field tails off in several years. A decision on this new system is expected after the end of the decade. This is just one of a number of ideas being analysed that over time may lead to offshore fields that can be operated remotely from shore. Though these would still be drilled and maintained using mobile rigs, there would no longer be a need for permanently moored platforms to manage them.

Though only a concept at the moment, that sort of breakthrough would have an impact on the offshore oil industry as profound as the introduction of the floating platforms that breathed new life into the Gulf of Mexico in recent years. The Ursa platform, meanwhile, will probably still be in production. It is expected to continue producing oil and gas for several more decades. No longer perhaps the largest or the deepest in the world, it will remain even then a remarkable reminder of how technology and determination can help meet the world’s voracious demand for energy.