Total increases output from marginal Otter field

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The field is one of the UK's new subsea oil fields in block 210 in the Northern North Sea, 21 km away from the host platform. It was discovered in 1978, appraised in 1997, and developed in 2002/2003. The field is a shallow compartmentalized accumulation with a measured reservoir depth of around 2,000 m and contains 36° API crude with estimated recoverable reserves of 42 MMbbl. Due to the low reservoir pressure, around 200 bar (2,900 psi) initially, coupled with the moderate gas-oil ratio of 450 cf/bbl, low bubble-point pressure of 143 bar (2,074 psi), and likely water production, the field required artificial lift to achieve development. The long step-out distance and flow assurance issues led to ESP technology being chosen as an artificial lift method for this development.

System design

A dual ESP completion design with two independent systems below the tubing hanger was selected to reduce the frequency of the workovers and allow workover periods to fit within a favorable weather window. These configurations have been previously used for high-cost intervention wells.

According to Eugene Bespalov, Baker Hughes Centrilift business development manager–UK, "The 20,000-b/d rated, 684-hp ESP system was designed for fluid production rates between 4,500 and 22,000 b/d to accommodate different production scenarios. The upper (secondary, or back-up) ESP system design included a higher number of stages to provide necessary total dynamic head (TDH) for a later stage of production when water cut increases."

Both systems use automatic Y-tools to provide intervention access through the 3 1/2-in. by-pass tubing, Bespalov says. A set of downhole parameters is available from each of the ESPs through the monitoring system that uses data transmission through the main ESP cable. Downhole parameters include pump discharge pressure, pump intake pressure and temperature, ESP motor winding temperature (MWT), motor vibration, and current leakage, he says.

Each ESP well is driven by its own variable-speed drives located on the host platform. Three 6.6-kV subsea power cables run to the template and then pass through the tree cap via a subsea switch that can direct the power to either upper or lower ESP. The subsea switch is a remotely activated hydraulically driven device using tree subsea control module (SCM) for hydraulic interface. The electrical tree penetration system was designed to by-pass the switch using an ROV, if required.

The production from each well commingles in the common 10-in. production pipe-line. The template has a multiphase flow meter, which can be routed to measure individual well production.

Drilling phase

"The drilling center is a four-slot template located beside an existing appraisal well. All three producers have horizontal drains ranging from 220-445 m long and were placed in the Tarbert formation, the highest unit of the Middle Jurassic Brent sequence," Kelman says. "Geosteering was used in conjunction with rotary steerable assemblies in order to ensure the drains were located in the highest quality sandstone and avoiding the unstable overlying Heather formation."

The initial plan for the field was to start drilling during spring 2002 to avoid winter operations in the North Sea. Rig availability issues moved the start of the Otter drilling campaign to July 2002. This resulted in additional complications caused by bad winter weather, as the completion process proved to be weather-sensitive.

Due to weather conditions and excessive rig movement for the second well ESP installation, the ESP packer lost its sealing elements while running in hole. By that time, it was obvious that performing the ESP completions was too weather-sensitive. The appraisal well was re-entered and completed, followed by drilling of the final producer.

This left three completions to be installed back-to-back (two oil wells and one injector well) in spring 2003. The same service crews were used throughout, which allowed continuation of experience, increased awareness of the sensitive completion operations, and ensured provision of high quality service.

Good logistical planning was vital to the success of the wells, as the rig size did not allow all the ESP completion equipment to be held aboard at once. A supply ship was used each time as extra deck space.

Rig-time saving

Bespalov says the ESP completion running sequence is time-consuming because of the precision required when assembling pumps, splicing cables, testing pressure and electrical components, and perform other operations. The one pre-planned activity was the sub-assembly make-up, which ensured precise motor lead extension (MLE) cables space-out. The by-pass pups and other completion components were included in the sub-assemblies below the ESP packer. All of the pup joints were precision cut to a tolerance of ±0.005 m. This meant the MLE could be pre-spliced onshore to a packer penetrator.

After all components were assembled, a good hook-up was ensured between two MLEs above the upper Y-tool. Any extra MLE cable lengths were then finely adjusted by the adjustable spacer sub (both cables simultaneously), and individual cable lengths were altered using packer penetrator adjustment subs located on the top of the ESP packer.

A program change to clean up the wells by flowing them to the host platform, instead of the original plan to clean up the well using the rig, saved considerable time. Although an attempt was made to clean up and test the first producer to the rig, the well could not flow naturally because of earlier losses of completion brine, which were now entering the wellbore. After reviewing, it was agreed to flow the well to the host platform using the ESPs if required. The production manifold was purged with nitrogen to ease well free-flow initiation. By the time the well was available to free-flow, it had enough pressure to flow itself, but through the lessons learned, it was decided to repeat this operation for the other two producers. The injector wells were perforated under balance to ensure clean perforation tunnels.

According to Kelman, the rig was on site for 340 days, during which time it drilled four new wells, recovered one appraisal well, and completed three ESP wells (one twice) and two injectors. Of that time, half was attributed to completion operations. Total project non-productive time (NPT) was 39%, most of which was attributable to weather. NPT during completions was 43%, which showed how weather sensitive this operation was. During this time, the rig experienced no lost time accidents and a total recordable incident rate of zero.

Commissioning program

The initial commissioning program included both topside and downhole system commissioning, Bespalov explains. "The ESP contractor provided the full-scale commissioning program as part of the EPIC (engineering, procurement, installation, and commissioning) contract structure."

The topside systems commissioning started in April 2002 after three individual self-contained modules, each hosting a variable speed drive (VSD) system, were installed on the Shell Eider platform.

The downhole system commissioning assumed that each ESP system would be operated for seven days minimum followed by the subsea switch changeover sequence to allow the second ESP to be commissioned. ESPs were tested at various frequencies and flowrates and were run shut-in ("deadheading") both forward and reverse to establish proper rotation.

The first well was commissioned in November-December 2002. The second and third wells were cleaned and commissioned in May-June 2003. Following the successful commissioning periods, the wells were then handed over to production.

According to Kelman, it was known that the wells would flow naturally once brought online, but there was no definitive time for the ESP's to be turned on full time. Based on the appraisal well information, the original field development plan forecasted that the wells would be capable of free flowing for approximately six months.

An ESP maintenance program was developed that included periodic ESP performance checks every three months to ensure system functionality and to clear any debris that could be accumulated in the system flow paths including the automatic Y-tools, according to Bespalov. Each ESP is run for seven days.

The program started in July 2003 and while primary systems remain operational, back-up systems (upper ESPs) are still subject to this rigorous maintenance program.

Operating philosophy

The ESP operating philosophy for dual system completions was discussed internally with field partners and ESP contractors, Bespalov says. After careful considerations of options and completion specifics, the following operating philosophy was taken as a basis of the initial period of the Otter field development:

• The lower ESP is started first and runs until failure with the secondary ESP (upper) being subject to commissioning checks
• Once the lower ESP is not operational, the upper ESP is put into continuous production mode.

Due to specifics of subsea systems, the wells are started up against closed production wing valves with the subsea choke partly closed (around 24%) until the wellhead pressure exceeds the main flowline pressure. Afterwards, the choke is opened to a pre-determined value to avoid back-flow issues. The ESP start-up sequence has three built-in protection timers to avoid uncontrolled start-up scenario.

Workover philosophy

According to Kelman, the high status of this field development along with the ESP redundancy philosophy led to the development of a separate workover policy. This included two complete sets of completion equipment that are held in preparation for a workover. The new pumps are kept in parts, as the number of stages could be modified with new information gained about the performance of each well. All the other equipment is held in storage.

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If the primary ESP fails, the secondary ESP can be used while a rig is mobilized, equipped, and procedures prepared for a workover. The aim is to start a workover three months after an ESP failure. This ensures long-term production of the field at steady rates. However, this philosophy is still to be tested, as some reluctance may be met to temporarily suspend production to workover a well with one fully functional ESP system.

Water injection system

Two water injection wells support the development, with one injecting the water into the underlying aquifer and another into the oil-bearing formation.

"Ironically the best producer receives the best water support," Kelman says.

This part of the reservoir is approximately 10 bar (145 psi) over-pressured. One other producer is supported, and the third has virtually no support apart from natural aquifer. The complex heavily faulted reservoir structure is the main problem in the latter case, but as this has been identified, it gives possibilities for side tracking an injector later, he says.

Production operation

Kelman says that after 12 months of operation, all three ESP wells are now operational full-time, delivering the required field production plateau of over 30,000 b/d. ESP's are operating at frequencies between 50 and 60 Hz, lower than planned, due to the delayed water breakthrough. First water production was detected approximately seven months later then expected (November 2003), but is slowly increasing (currently at 18%).

The production level had been originally reached with the first two wells flowing naturally. This continued with the use of the ESPs and is still the case today, more than 12 months after first oil and several months after plateau was reached.

There were no significant ESP-related events experienced to date, except for an unexpected water-slugging observed in one of the wells, which has the least water support. The problem was identified, analyzed after three start-up attempts, and eliminated after appropriate modifications to the ESP start-up sequence were successfully implemented.