Designer wells, injection techniques prolong production from core fields

Elf Petroland's K5-EN/C gas production platform was installed by the Stanislav Udin crane vessel in June. (Photo courtesy Elf Petroland) [8,863 bytes] A significant reduction in field costs has contributed to a longer life for Norsk Hydro's Oseberg Field. [3,628 bytes] Saga is pioneering the use of foam to enhance production on the Snorre Field. [11, 366 bytes]

Revitalization of major producers to boost recovery by 16%

Nick Terdre
Contributing Editor - Norway

Recent technological advances, particularly in drilling and well technology, are enjoying singular success in extending production on producing fields. Nowhere is this truer than in Norway, where the 16% increase in total recoverable reserves unveiled earlier this year by the Norwegian Petroleum Directorate was largely due to improved recovery on existing fields.

Four operators - Amoco, Norsk Hydro, Saga, and Statoil - recently described how they are keeping the oil production underway on the Valhall, Oseberg, Snorre, and Statfjord fields. The following are their comments:


Since production on the Valhall Field started in 1982, Amoco has successfully raised its recoverable reserves estimate from an initial 247 million bbl to a current 623 million bbl. According to resource manager Hugo Halvorsen, there are good possibilities of further improving recovery, and the company has now set itself a target of one billion bbl.

Amoco is currently seeking approval for a water injection project, which would involve installing a dedicated platform- the field's fifth - housing some 15 wells. The scheme is dependent on fiscal relief, Halvorsen says, but if the go-ahead is given this year, opening the way to start-up in 1999, additional production of some 100 million bbl could be achieved by 2011.

A water-flood scheme involving the injection of some 180,000 b/d is in the final stages of implementation.

From the start, Amoco found it necessary to use special well completion techniques on Valhall, which is a chalk field with soft formations. Gravel packing was introduced in the mid 1980s.

In the late 1980s, the company found that the field contained more energy than expected, as a result of compaction. So, the same effect which caused the platforms to suffer subsidence - they have sunk 3.2 meters so far, and remedial action may be required in about 10 years' time - made additional reserves available at the same time.

A program of long-reach and horizontal wells has been implemented to tap these reserves. Fracture stimulation is used in completing horizontal wells - typically up to six such operations in a well - giving at times a substantial increase in productivity.

Much of the increase in reserves has been achieved through improved reservoir modeling, Halvorsen says. Amoco has developed a method known as the coherency cube, akin to seismic anomaly technology, which uses biostratigraphy to identify fractures and their orientations. New wells are now being drilled from the 15-slot wellhead platform installed last year. Some of these are taking longer than expected to due to problems with well-bore stability.

Amoco's first splitter well is also being drilled this summer. This is essentially a means of getting two wells, each with its own wellhead, from one borehole. In this case the common borehole will be drilled to about 1,300 meters, at which point each well - one is a producer and one a waste injector - will go its separate way.


As it nears completion of its ninth year in production, Norsk Hydro's Oseberg Field is still pumping out some 500,000 b/d. The field's long-term outlook is also considerably enhanced, reserves having been virtually doubled from an initial 1 billion bbl to a current 2 billion.

The story so far is one of oil production assisted by gas injection. Not only is the field's own gas put into the reservoir, but so is up to 10 MMcm/d from the Troll field under the so-called Troll Oseberg Gas Injection (TOGI) project. "To date some 20 bcm of Troll gas has been injected into Oseberg," says Torgeir Kydland, vice president for Oseberg and Visund exploration and production. "It has had a major impact, contributing an additional 315 million bbl to recoverable reserves."

With the aid of the gas injection program, the drop in reservoir pressure has been kept to within 30 bar of the original level.

Drilling technology has also played an important role, according to Kydland. When development plans were drawn up in 1983, they included 21 subsea wells to tap areas beyond the 3.3-km outreach of the platform wells. In the event, as the outreach has been extended to some 7.5 km, a smaller number of subsea wells were drilled, and of these only one is still producing.

Instead the story has been one of horizontal wells, which have added additional reserves estimated at 125-155 million bbl. So far, 32 such wells have been drilled. The most recent is C-26A, which filled the last undrilled gap between the platforms, which are located at either end of the field.

During completion of the wells, special perforation and spacing techniques are used to optimize the inflow. Hydro has also had success in locating and producing from the randomly distributed Ness or channel sands to be found at Oseberg, which are difficult to locate on seismic. One technique has been to extend the ends of horizontal wells upwards in the hope of hitting Ness bodies, essentially a pot-luck method that has proved worthwhile.

The operator has also developed specific Ness wells. These are wells with dual completions with one branch going into the main reservoir and the second targeting likely Ness areas. An estimated 140 million bbl has been added to reserves through production from these sand bodies.

Come the millennium, oil production virtually will cease as gas production takes over. This is due to begin in 2000, using process facilities on a dedicated platform. However, the field's oil processing facilities will be kept busy handling production from the Oseberg East and South satellite fields, which are due on stream in 1998 and 2000 respectively.


Saga's efforts to realize the potential of the Snorre field have borne substantial fruit. Recoverable oil reserves have been increased from 765 million bbl in the 1987 development plan, when the field was assessed to have a negative net present value, to a current 1.315 million bbl.

Plateau production will continue beyond 2020. The company is currently in the throes of planning the development of the estimated 250 million bbl in Snorre North - a choice between a floater and subsea wells tied back to the existing platform should be made by autumn.

Improved recovery is largely due to advances in drilling and well technology and the use of reservoir injection programs, according to Erik-Sverre Jenssen, vice president in Saga's petroleum technology department.

In July, the company was to install the world's first surface controlled reservoir analysis and management system (SCRAMS) on one of the Snorre wells. This is a remotely operated inflow control valve or sliding sleeve which enables production from different levels in the well to be selectively controlled, and can thus enhance productivity.

Since the field came on stream in 1992, improved mapping has opened the way to successful production from zones which had earlier looked unpromising, Jenssen says. Well patterns have been enhanced, with the result that the number of planned wells has been reduced from 100 at approval to 77.

Saga is now investigating the possibility of large-scale foam injection. The firm's experimental work with foam over several years has led to the formation of a NKr 10 million project backed by the EU's Thermie program.

The company is now preparing to inject foam through an injection well which, if it works as intended, will carry gas down in the formation to within range of a nearby producer. Work is also being carried out on using gel to prevent water breakthrough. The water cut is now around 30% and rising, and an active reservoir management program which will include redrilling and sidetracking existing wells will be required to tackle it, says Jenssen.

The probability is great that water and gas injection (WAG), which has been piloted on one of the central fault blocks since 1994, will be extended to other fault blocks. Process capacity on the Snorre TLP, which has already been increased to 250,000 b/d (plus another 100,000 b/d dedicated to Vigdis), will probably have to be expanded.


Now well into the decline phase, the giant Statfjord Field presents tough challenges for operator Statoil. However, thanks largely to better knowledge of the reservoir, a successful well intervention program and fresh drilling, production has been revitalized.

Statoil recently announced that it had set a target of achieving a 70% recovery rate, equivalent to producing 4.4 billion bbl of oil. This represents a 500 million bbl increase in the recoverable reserves estimate. Field life would be extended to 2020.

Production is now running in excess of the level forecast in the 1997 plan, and the company believes it will be able to lift it to 30% above the current level by 2000, according to Kaare Rosandhaug, vice president for Statfjord operations.

The development of some 85 million bbl of oil contained in the northern flank is now under study, with subsea wells tied back to Statfjord C recommended in preference to long-reach wells from the platform.

Gas and water injection have been used on the field since start-up. Gas injection has been particularly effective on the Statfjord formation, where up to 80% recovery is expected in some zones.

Deviated drilling and coiled tubing drilling were introduced in the mid 1980s, and horizontal drilling in the early 1990s. All wells are now designer wells, says Rosandhaug. 4D seismic is used to plan trajectories. The latest 3D survey is due to be shot this year.

This summer has seen the drilling of the C-23 well, Statoil's first multilateral well with a full casing program for both laterals. To kick off the second lateral, a mill-through tool was used to penetrate the casing.

Significant time savings were achieved by using Baker Hughes Inteq's Autotrack rotatable drilling system on one of the laterals. An average 40 meters per hour were achieved on the final 1,200 meters.

C-23 is to be drilled through the last available slot on any of the field's three platforms. All new drilling will have to be performed using the existing well slots. Later this year, the first coiled tubing sidetracks will be drilled.

The main contribution to slowing the production decline comes from well intervention, Rosandhaug says. Without extensive workovers, output would drop by half this year.

The main methods used are wireline operations, which have been facilitated in horizontal wells by the advent of the well tractor which Statoil helped to develop, coiled tubing operations, snubbing, drilling rig operations, and pumping.

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