Employs a technique not previously used
Kerr-McGee North Sea (UK) Ltd.
On Aug. 28, 2002, the UK continental shelf (UKCS) Tullich oilfield was brought onstream as a subsea satellite to the existing Gryphon infrastructure. This was achieved within schedule and budget, and production rates have subsequently surpassed the anticipated plateau of 15,000 b/d.
When operator and 100% interest holder Kerr-McGee drilled the two-well and six-sidetrack Tullich appraisal program in 2001, it was the follow-up to what was initially a Hamilton Brothers discovery made in 1991. At the time, the technology was not available to economically exploit these reserves.
Tullich drilling and logging BHA for 8 1/2-in. reservoir section.
The 9/23a discovery did not merit mention in the UK Department of Trade & Industry's "Brown Book" at the time, as it was not regarded as significant. A decade later, a change of license ownership, the march of technology, and Kerr-McGee's assessment of the reserve potential made the difference in the economic feasibility of Tullich.
The Kerr-McGee appraisal program confirmed the original Hamilton view that the hydrocarbons were trapped within thin sands in the Balder interval, and it became clear that significant ingenuity would be required to successfully exploit the geologically complex reservoir. A project team was assembled, and Schlum-berger was brought into the frame late 2001, following discussions with various contractors.
Location of the Tullich field, North Sea, United Kingdom.
With individual reservoir thickness below the limit of seismic resolution and a restricted depth window for completion, optimal placement of the intended suite of four horizontal production wells to ensure maximum drainage was key to achieving a viable development. In particular, being able to remain in these thin sands while drilling the wells would be a challenge.
Different options were evaluated with regard to real-time logging suites and rotary steerable devices, without which commercial development would be impossible. Schlumberger's real-time geosteering capability gave the company the edge at contractor selection – formation imaging visible while drilling from the Geovision resistivity and vision azimuthal density neutron logging-while-drilling (LWD) tools.
Before drilling started, the use of appraisal well wireline log data such as mini-fracture tests, formation pressure measurements, borehole imaging, and seismic data analysis to help characterization of a field-wide stress model was made. This model aided understanding of the best drilling directions and mud weight limits that would be needed to successfully drill the wells.
The initial intention had been to use water-based mud, though this presented a challenge in itself. The resistivity tool's technology characteristics were such that the system delivered better images using these drilling fluids than with oil-based counterparts. The oil-based fluids were eventually employed for Tullich because of the inherent advantages when carrying out horizontal drilling.
Because of the decision to switch to oil-based muds, the engineering center was asked to devise real-time gamma ray imaging sensors for the resistivity tool capable of compensating for the loss of resistivity imaging and which would be located close to the bit. This was duly accomplished. Also, the resistivity tool qualitative bit resistivity capability, which allows rapid differentiation between oil-bearing sands and non-reservoir rock during drilling operations, was applied for the last two wells.
Notwithstanding such precautions, recognition within Kerr-McGee that Tullich would be challenging proved correct, particularly with the first development well (9/23a-T2). It proved necessary to employ a technique not previously used by the drilling department, namely drilling open-hole sidetracks to repeat horizontal sections at different stratigraphic levels.
The PowerDrive rotary steerable system was fitted with an active gauge polycrystalline diamond compact bit that aided the sidetrack kick-off process. The openhole sidetrack technique also enabled cutting of vertical sections to find the target sand and again was achieved without tripping out the drill string – a significant accomplishment in itself.
The first sidetrack targeted a higher stratigraphic level and fared slightly worse than the initial drilled well in terms of sand encountered. Two further T2 attempts were made, by cutting vertical sections with openhole sidetracks designed to go downward as rapidly as possible. With the additional LWD and imaging data provided by these openhole sidetracks, it was possible to complete a well through all the sands encountered. The completed well produced at a peak rate of 3,500 b/d. An aggregate 11,479 ft of section was drilled between the T2 main wellbore and the four sidetracks.
Drilling of the T1 (3,852 ft horizontal, 10,766 ft TD), T3 (5,095 ft horizontal, 12,215 ft TD), and U1 (5,606 ft horizontal, 12,491 ft TD) producers was straightforward by comparison, with each delivering between 5,000 and 8,000 b/d.
Reservoir performance to date is considered excellent, with bottom-hole pressure stabilizing rapidly for all four wells soon after first commercial production. This indicates that Tullich may not require water injection in the future. Pressure support appears to be provided by either an extensive aquifer below the oilfield or the gas cap above. Given the experience gained with Gryphon, water breakthrough had been expected early, perhaps three months into prod-uction. Nearly six months in, there was still no sign of water breakthrough.
Schlumberger's real-time geosteering capability gave the company the edge at contractor selection (formation imaging visible while drilling from the Geovision resistivity and VDN Vision azimuthal density neutron LWD tools).
Throughout the drill-ing process, the logging suite performed effectively, delivering the crucial real-time data necessary to enable the dev-elopment team to evaluate whether sands were being appropriately inter
sected, determine which way they were oriented, and modify the well path appropriately.
MWD/LWD data was transmitted and delivered in real time to all team members to facilitate efficient decision-making at Kerr-McGee's UKCS headquarters in Aberdeen. Occasionally, it was necessary to wait 30 min or so for the processing of exact formation dip data from the images, but in geosteering terms, it was relatively instantaneous.
Standard data delivery would normally involve one or two faxed logs per day in total. Being able to use the image-derived formation dip data to predict in real-time which way the sand trended was a real innovation and made it possible to maximize the intersection of the wellbore with the reservoir sands.
Previously, LWD borehole imaging data was available in memory for examination after the drill string and tools had been retrieved. Only then would it become evident whether it was necessary to go back in and drill a different well path.
This marriage of openhole sidetracking and constant access to real-time logging data, coupled with integrated teamwork between operator and contractor, meant well costs could be contained. The original rig schedule allowed 200 rig days, whereas the final count was 208. Rig time and cost overrun could have been significantly greater had a less innovative approach been applied. It is important to note, however, that development well footage was to have been 46,000 ft, but the additional openhole sidetracks pushed this to 54,000 ft, which is a significant increase.
Wellbore stability was excellent throughout the drilling campaign, aided by the Schlumberger workflow approach. There were no requirements for costly sidetracks or re-drills because of borehole instability, and all completion strings were successfully run.
On the whole, equipment performance during drilling was very good, though there were some hitches. Crucially, the all-important LWD system operated efficiently and there were only minor equipment failures during the openhole sidetracking operations, which is a significant achievement given the challenge presented by the thin reservoir sands. Because of its immense length, it proved necessary to modify the tool string due to more formation wear on the LWD component than had been expected.
T2 well and openhole sidetracks (T2Z, T2Y, T2X, T2W), cross section.
In 14 bottom hole assembly (BHA) runs, 26,052 ft was drilled with only one trip for a downhole tool failure, and, aside from the T2 well, development was no more difficult than was originally anticipated.
Experience gained from drilling Tullich in this manner provides valuable pointers to future development activity in the Gryphon area, including tackling reservoirs of similar geological complexity. Even in situations where oil-based muds are used during drilling operations, it will be possible to collect real-time downhole images of sufficient quality to successfully geosteer within reservoir sands and to chase them using openhole sidetracking in a cost-effective manner.
Further, as a result of the success achieved while openhole sidetracking the T2 Tullich well for horizontal sections and cutting vertical sections off horizontal sections as pilot holes, it should be possible to use this approach during appraisal drilling, rather than more conventional and costly approaches.