TTRD technology improves recovery, cuts costs in mature fields

The structural map of the top Tarbert indicates the proposed 34/10-B-1 B well along with neighboring wells.

The more expensive alternative is to pull out the existing tubing before re-entering and drilling again into the reservoir. Not only must the tubing be replaced, but also a longer well must be drilled. The TTRD technique allows a sidetrack to be drilled out deep within the well and close to the reservoir. Consequently, the transport stage of drilling from surface to the reservoir is already done. Savings are around $1.5 million to $3.1 million per operation performed on production platforms, and the method further improves recovery because reduced costs permit the exploitation of marginal or uncertain reservoirs.

The company adopted the through tubing drilling (TTD) in 1997, when it drilled and completed two sidetracks with the aid of coiled tubing. Drilling TTD sidetracks from production platforms using jointed pipe rather than coiled tubing eventually proved more cost-effective and technically efficient. In 2000, the company performed the first jointed-pipe TTD operation and has since used the method in an additional 13 wells.

Statoil limited the TTD technique, applied in the Statoil’s Gullfaks, Statfjord, and Veslefrikk North Sea fields, to existing wells that stopped producing. In these cases, the operator placed the sidetrack in an undrained area of the reservoir to tap into remaining hydrocarbon pockets.

The PowerDrive Xtra 475 RSS for 6-in. holes has no stationary components and provides full rotation of the entire drillstring at uniform speed.

TTRD is now considered successful when sidetracks are drilled from producing wells without jeopardizing or losing existing reserves from the parent track. As such, the company has focused its efforts on identifying and developing methods for producing from both the parent track and sidetrack, thereby creating multilateral wells.

RSS tool for TTRD

During this time, Schlumberger developed a new RSS for a 6-in. hole size for TTRD applications based on its experience with the PowerDriveXtra475 RSS. The technology enables full rotation of the entire drillstring at uniform speed. The RSS has no stationary components to create friction that reduces efficiency, and it essentially has no physical “anchor” to hold up the bottomhole assembly (BHA) during drilling. Drilled cuttings flow past the BHA to ensure that fewer cuttings are reground, which serves to maximize rate of penetration.

In 2004, Schlumberger introduced RSS technology for slimhole drilling and TTRD applications. Having an RSS for such applications has helped the industry reach smaller targets in mature reservoirs like those in the North Sea more cost effectively, while achieving drilling performance comparable to conventional hole sizes.

In the past, displacement motors have been used for directional control in TTRD applications. Steering with motors can be problematic in slim holes, as weight stacking and twisting drill pipe makes it difficult to maintain directional control. The introduction of slimhole RSS for TTRD use eliminates these problems and also helps with hole cleaning since the entire drill string rotates continually. This technology reduces drilling costs because the need to pull the completion string for redrills is eliminated. The cost reductions enable field life extension and economic recovery of small pockets of trapped hydrocarbons in mature reservoirs.

In June 2004, Statoil used 3D RSS technology in its Statfjord field to drill the first TTRD well.

The TTRD technique involves running a whipstock and a window milling assembly through an existing christmas tree completion and milling a window below the existing tail pipe. A slimhole wellbore is then drilled into the reservoir and a liner usually is run to complete it. All of the operations are carried out through the existing completion, eliminating the time and cost associated with pulling the old one and running a new completion and tree when the drilling phase is complete.

Challenges

While a cost-effective way to increase recovery, TTRD presents special challenges for the planning, drilling, and execution phases. The safety nipple must be protected from wear during the drilling phase to avoid damage that could compromise the integrity of the equipment upon completion. The safety nipple is less than 6 in., so a slim hole must be drilled with a 5 7/8-in. bit.

Schlumberger skinned down a bias unit to optimize operations in a 5 7/8-in. hole and fitted the control collar with a 5 3/4-in. integrated blade stabilizer to develop the slimhole RSS for the TTRD application. The company recognized that the largest challenge was the high equivalent circulating density (ECD) encountered in through tubing operations. Having the production liner/tubing remaining all the way to surface induces ECD, so the flow must be kept low.

Statoil funding helped support the development of a special low-flow version of PowerDrive 475 that Schlumberger designed specifically for this TTRD flow situation with the 34/10-B-1 B well, marking the second time of its use.

Gullfaks TTRD program

The Gullfaks reservoirs consist of the middle Jurassic Brent Group, lower Jurassic Cook Formation, and lower Jurassic to Triassic Statfjord formations, where the Brent Group contains the majority of the hydrocarbons. Gullfaks field’s production peaked in 1994, and about 90% of the base reserves have been produced to date. The structural setting of the field is complex, representing one of the main factors of uncertainty regarding its drainage. So, the TTRD has been identified as a cost-effective method of providing new reservoir drainage points, which included the 34/10-B-1 B well to improve recovery and extend field life.

Statoil’s primary objectives are to prove the presence of and produce the remaining hydrocarbons in the Tarbert and Ness formations in fault segment H5. The company picked the targets based on well data from surrounding wells (B-3 A, B-23, B-2, and B-30), which indicated oil above 1,895 m TVD MSL in Tarbert-1B (based on B-3 A information), above 1,809 m TVD MSL in Ness-2C, and above 1,829 m TVD MSL in Ness-2B1 (based on B-2 information).

To efficiently drain the area of attic oil, the company positioned the well just below the reservoir’s ceiling. Initially, it planned the well total depth in the lowermost Tarbert formation because of anticipated low pressures in Ness-3D. However, new information from B-30 showed that Ness-3D had been pressured up during the summer of 2004, thus facilitating drilling the Ness formation, which had remaining oil in Ness-2 B1 and possibly in Ness-2C. Also, the B-3A well drilled in early 2003 did not record abnormally low pressures in the Ness formation.

Statoil planned the B-1 B well as a TTD& C well with a cemented 4.5-in. liner. It planned kick-off at 1,738 m MD RKB (1,603 m TVD MSL) in the Lista formation, with total depth at about 3,285 m MD (1,804 m TVD MSL) in the upper part of the Etive formation.

Well/sidetracks

Statoil began drilling the 34/10-B-1 B well with the Statfjord drill crew on Nov. 9, 2004 with a PowerDriveXtra 475 RSS tool. The well encountered the Base Cretaceous Unconformity (BCU) 8 m higher than expected and consequently came in before a planned drop in the well path. The crew drilled at a very low rate of penetration, nearly parallel to the formation dip. As a result, it drilled an openhole sidetrack with a steeper well path through the BCU and continued as planned to the top of the Ness formation.

Schlumberger cemented the hole back at this point because of a massive loss situation, which probably resulted from depleted pressure in the Ness-3D. The B-30 well showed increased pressure in Ness prior to drilling, but it was also open in other Ness zones, making the N-3D pressure indication uncertain. Data acquisition in B-30 after drilling B-1 B showed leakage of the 10 3/4-in. casing in the Tarbert formation.

The drill crew planned a new well path to reach total depth before the top of the Ness. Logs from track 34/10-B-1 BT2 showed a more consolidated section in the bottom of Tarbert-1B, which would give the best sand control during production.

As a result, the company made this optimal section as long as possible by deflecting the planned well path to the northeast. The drill crew drilled the new track, 34/10-B-1 BT3, into Tarbert-1B, but hit cemented rock, probably cemented sandstone at the BCU, which prevented drilling through before reaching the optimal area. As such, an openhole sidetrack was made, 34/10-B-1 BT4, going deeper to avoid hitting the BCU again. This time, steering was kept at a minimum to avoid further problems. The result was a well path going east, and the drill crew set total depth at 2851 m MD in Tarbert-1A.

Statoil drilled the B-1 BT4 well and entered the Tarbert reservoir, with the uppermost 3 m of the Tarbert-2 and the entire Tarbert-1B reservoir zones oil-filled. The company perforated the well and put it onstream for production on Jan. 8, 2005. After two days the well produced with a 10% water cut. The company limited the production rate to 1,000 cu m/d or less because of decreasing reservoir pressure and increasing water cut. There also has been some sand production.

Statoil performed the last production test March 25, with an oil rate of 677 cu m/d, a 33% water cut, a 105 cu m/cu m gas-to-oil ratio, and a 122 bar wellhead pressure (approximate PI of 200 cu m/d/bar).

Statoil observed considerable cost savings for the two openhole sidetracks. In addition to the TTD/TTRD successes from platforms, Statoil has made considerable progress with planning TTRD operations in subsea completed wells from mobile drilling units. Plans are currently underway to perform the first job of this kind in the Norwegian North Sea.•