FEA modeling system delivers high-angle well bore through hard formations

Tullow Oil plc has interest in two exploration licenses offshore Ghana. In 2007, the operator drilled two successful exploration wells, Mahogany-1 and Hyedua-1, that discovered Jubilee field, which straddles the boundary between two blocks: Deepwater Tano and West Cape Three Points. Results from three accelerated appraisal wells drilled during 2008 – Mahogany-2, Hyedua-2, and Mahogany-3 – confirmed that Jubilee field is a continuous stratigraphic trap with potential resource of approximately 1.8 Bbbl of oil.

Formation challenges
Jubilee is one of the only deepwater developments with an extensive section of hard and abrasive formations. After drilling the first four wells in the Jubilee region, engineers individually identified several hard and abrasive formations through the reservoir section starting at the top Upper Mahogany to base Lower Mahogany. Of these four wells, three were drilled in the Jubilee field including:
• Mahogany-1;
• Mahogany-2 ; and
• Hyedua-1.

Rock strength software program used sonic/gamma ray logs to determine lithology and UCS. (Image courtesy of Smith International)

Using log data obtained from the three test wells, a proprietary rock mechanics program quantified the formation’s compressive strengths ranging between 6,000 and 10,000 psi with turbidite stringers peaking at 25,000 psi. These formation properties are unusual in a deepwater environment. An analogous hard and abrasive deepwater drilling application has been referenced in a Society of Petroleum Engineers (SPE) and International Association of Drilling Contractors (IADC) paper, SPE/IADC paper 105201. In that application, hard and abrasive sands were drilled successfully by a seven-bladed PDC bit with 16-mm cutters.

Hyedua-2
The next phase of development started with Hyedua-2, which required a core of the reservoir sand. The 121?4-in. hole section would require a minimum of two bits, one to drill the section to core point and the other to drill below the cored interval to total depth (TD). The initial PDC, a seven-bladed design (16-mm cutters) successfully drilled the overburden, but once it penetrated the top of the reservoir sand, it wore quickly, confirming the abrasiveness of the formations. Below the cored interval, a nine-bladed PDC bit drilled 187 ft (57 m) and was pulled with a dull grade of 1-2-WT-S-X-I-CT-PR. Although the short run length was disappointing, according to the operator, further analysis indicated the bit was stable and had worn out due to formation abrasiveness. To successfully drill this application, engineers had to address both bit design and cutter technology.

Plotting of lateral vibrations at different string and motor RPM combinations is shown. The Y axis represents distance from bit. The X axis represents lateral vibrations in G’s. Red lines from the drillstring are contact force vectors (magnitude and direction of contact forces).

Post-well analysis
Using a finite element analysis (FEA)-based dynamic analysis system, application engineers began a series of virtual tests to develop an optimized PDC bit for the reservoir section. During the time it took to analyze the results of Hyedua-2 and develop the improved bit design and cutter technology, three additional development wells were drilled. Several different bit designs were tested with various operating parameters to control excessive wear and torsional/lateral vibration. Due to excessive shoulder wear, the new design included eight rows of backup cutters to redistribute cutter loading.

The optimized bit design, with new cutter technology (MDSi816) was completed and manufactured in 1Q 2009 and run on Jubilee-02. The new bit and cutter combination, along with optimized operating parameter selection, successfully drilled the entire 121?4-in. section in one run.

Further refinement of the preferred PDC bit and operating parameters resulted in significant performance improvement.

Having designed a bit durable enough to drill the section in a single run, engineers focused on minimizing the high vibration levels. By working closely with the bit and directional drilling contractors on the bottomhole assembly (BHA) design, Tullow was able to improve penetration rates on Jubilee-5, but more importantly, avoid the damage/early failure of the logging-while-drilling (LWD) tools and the requirement for subsequent wireline logging runs.

Vibration reduction, FEA modeling
Focusing on the most recent offset well, Jubilee-02, the objective of the study was to identify potentially damaging drillstring dynamics, particularly stick/slip and lateral vibrations, and make recommendations for improvement.

The methodology of the analysis was:
1. Identify conditions of stick/slip and whirl of the identified well;
2. Replicate drilling conditions through simulations of the
offset well to understand
drilling dynamics;
3. Run dynamic simulations for
different BHAs;
4. Run dynamic simulations for
different weight-on-bit and RPM combinations to identify conditions that induce whirl and stick/slip; and
5. Make final recommendations of drilling system.

The well profile for Jubilee-05 is shown.

After matching field measured drilling conditions through simulations and investigating several different BHA configurations, an appropriate range of weights and RPMs were recommended by identifying the areas of whirl and stick/slip. The final recommendation included the eight-bladed,
16-mm bit with the motor assisted push-the-bit rotary steerable system.

Modeling results
The next well, Jubilee-05, required a tangent section with an inclination of 49? with TD at 13,750 ft (4,192 m).The FEA modeling recommendations and bit strategy were applied and contributed to a 138% rate of penetration (ROP) increase, up from 29 ft/hr (8.9 m/hr) on Jubilee-02 to 70 ft/hr (21.2 m/hr) resulting in overall savings of approximately US $3 million. The bit was pulled in good condition and no tools, including the rotary steerable or MWD/LWD tools, failed or needed repairs. Overall, the vibration levels were lower on Jubilee-05 than Jubilee J-02. Compared to the three-well offset average (six bit runs), the new style PDC bit has drilled 165% more footage (5,583 ft or 1,702 m) with an ROP (70 ft/hr) increase of 122%, in addition to completing the hole section in one run.

Jubilee-05 (r) shows significantly lower overall stick/slip than Jubilee-02 (l).

The results of the improvements were measured on a well-by-well basis, benchmarked, and used to set targets for upcoming operations to continue to drive performance improvement. As Tullow continues to raise individual performance benchmarks, further performance gains have become more difficult to achieve as the company progresses through the Jubilee campaign. Tullow Oil will continue to build on past successes to realize best-in-class performance in Ghana deepwater operations.