Pre-drill modeling, MWD/LWD, rotary steerable work together to drive efficiency in deepwater project
By Jerry Webb, Weatherford
Far from being a mere buzzword, efficiency is a critical driver in all E&P operations. In deepwater drilling, efficiency has become a more elusive goal as wells are drilled farther from shore, in deeper waters and in more geologically complex reservoirs. The industry increasingly relies on directional drilling advances, such as rotary steerable systems (RSS), to deliver deepwater wells while minimizing NPT, lowering safety risks and staying within budget.
An operator in the Campos Basin offshore Brazil was in need of a more efficient solution during a five-well drilling campaign from May 2008 to August 2013 in a water depth of 4,650 ft (1,417 meters). The first three wells were drilled as vertical holes with no need for an RSS. However, the drilling services on these wells suffered from delivery delays and performance challenges that required more trips downhole and added rig time. These issues had to be resolved in the remaining two wells, and a directional drilling component had to be added to the final well to meet the operator’s objectives of delivering a smooth wellbore all the way to target depth (TD).
The operator approached Weatherford for assistance using the service company’s integrated drilling services. This offering combines services, including predrill modeling, measurement- and logging-while-drilling tools and the Revolution RSS, to deliver smoother wellbores while providing more completion options and less NPT.
Several objectives had to be met in the final well that were different from the previous four wells. First, the well was to be drilled in an S-curve configuration because the operator determined that this was the most efficient way to land the wellbore in the center of the four targeted perimeters. The desired drilling system would also minimize tortuosity of the well to eliminate ledges and possible hang-up points that might present problems for subsequent casing-running and completions operations.
Directional drilling via an RSS provides a smoother, less tortuous wellbore with a gun-barrel profile. On an ultra-deep well such as this, an RSS also eliminates the significant torque and drag forces that can arise when drilling with a mud motor. If string rotation is stopped while drilling with a mud motor, the entire drillstring has to move again to commence drilling. Drag forces are extended across the length of the string, making forward or backward movement difficult.
Other drilling objectives varied with depth and the particular hole size section to be drilled out. An upper 36-in. by 26-in. section required jetting in 36-in. casing and setting with less than 1.5° inclination, followed by drilling ahead the 26-in. vertical hole to section TD.
Next, a 17 ½-in. section was to be drilled in one bit run with minimal vibration in the bottomhole assembly (BHA). Significant vibrations in this section on previous wells contributed to a shortened operating life for the BHA components, which required an average of five bit runs to drill the section to TD.
The lower 12 ¼-in. section would contain the S curve and required drilling with the RSS to achieve less than 2.5°/98 ft (30 meters) of dogleg. The section vertical was to be landed above the sag formation target, using near-bit gamma ray to determine casing point. Finally, the operator required both real-time and memory LWD sonic data for this section.
To deliver these objectives, the wellbore was first modeled to understand how the BHA and drillstring should be configured to minimize vibration and ensure minimal trips. A simulation software package was used for this purpose, with parameters from the various BHA components used as inputs, as well as expected tortuosity based on experience in previous wells.
This simulation work helped optimize the BHA design and the number of stabilizers required to protect the various tools from vibration-induced damage. For example, the modeling indicated the degree of compression and buckling expected in the drillstring during drilling. The model also factored in changes to variables that would influence vibration and buckling, including rotary speed, changes to weight on bit (WOB) and the number of stabilizers already present on the BHA.
Armed with this information, the drilling team optimized the number of stabilizers required to prevent measurement tools in the BHA from impacting against the wellbore wall, which would lead to premature failure of the electronics housed in these tools. This helped keep the total number of stabilizers as low as possible and guided their placement on the drillstring for maximum efficiency.
The integrated approach to delivering this ultra-deep well helped the operator achieve its objectives at each stage of the drilling process. In drilling out the upper section, the 36-in. casing was successfully jetted in and reached TD with an inclination of only 0.25°. The jetting BHA was spaced out as required with no modifications. The 26-in. vertical section was subsequently drilled with no slide corrections required at an average ROP of 129.3 ft/hr (39.4 meters/hr). Weatherford did not record any NPT and completed the section in three and a half days, which was three days ahead of the operator’s authorization for expenditure (AFE).
The 17 ½-in. section was then drilled with an average ROP of 27 ft/hr (8.2 meters/hr) and a substantial reduction in BHA vibration. The upfront modeling work guided the BHA design, which helped minimize vibration and optimize LWD measurements. For example, a special stabilizer designed to be run with the RSS assembly provided better bit centering, which eliminated whirl and focused drilling power at the bit face.
The simulation work also indicated the optimal location for a stabilizer that would dampen oscillation at a problem spot on the BHA. Somewhat surprisingly, the simulation suggested that a stabilizer should be placed nearly 70 meters (231 ft) behind the drill bit, much farther behind the LWD collars than conventional wisdom would suggest.
A stabilizer placed at this location did indeed minimize oscillations and improve the performance of the LWD tools. This outcome also suggested that to truly minimize vibration problems in a BHA, one should not limit their search to a narrow section around the logging tools but should extend out to a larger area that covers the entire lower section (300 ft) of the drillstring and BHA.
This section was run to TD with the same bit and BHA in two runs. The second run was required because the operator wanted to investigate the cause of a pressure spike on the BHA. The bit was in excellent condition after drilling this section, compared with the poor condition of the five bits that were required to drill this section on previous wells. The significant reduction in bit runs allowed this section to be completed 7.5 days ahead of the operator’s AFE.
The lower 12 ¼-in. section containing the S curve configuration was drilled with the RSS, with a maximum inclination of 34.1° and an average dogleg severity of 2.56° – only 0.06° off of the planned dogleg severity. The well was brought back to vertical at 15,433 ft (4,704 meters) TVD, which was determined via near-bit gamma ray. The gamma ray tool is designed as an insert that can be housed inside the RSS and close to the bit for more accurate wellbore positioning. This section was drilled in two runs, with an average ROP of 22.2 ft/hr (6.77 meters/hr), and real-time and memory-recorded sonic data were provided throughout the section.
The integrated modeling, while-drilling measurements and RSS helped the operator meet its objectives for each section. A smooth, gun-barrel quality wellbore was delivered to TD, which will help improve the speed and efficiency of subsequent casing-running and cementing operations. The BHA stabilization provided by this service was a major factor in delivering this well with significantly fewer bit runs, high average ROPs for each section and nearly two weeks ahead of the time allotted in the AFE.