During the field-development life of a mature extended-reach drill (ERD) project, a wide range of drilling tools and practices were introduced to continuously improve drilling performance and well delivery times. One of the main challenges encountered in the ERD wells was in the 12¼-in. curve section, and drilling through interbedded hard layers with severe downhole stick/slip and downhole vibrations. Historically, both motor and motorized rotary steerable system (MRSS) bottomhole assemblies (BHAs) were used to drill this section. However, the motor BHA's lower rate of penetration (ROP) and weight transfer problem cause it to be an economically inefficient strategy in contrast with the MRSS BHA, successfully drilled through all of the challenges with higher ROP and a relatively lower overall cost. Driven by cost reduction necessity, an intensive engineering effort was implemented by the operator and service provider drilling engineering teams to change the motor BHA into a cost-effective drilling strategy for the challenging 12¼-in section. Analyzing the design and performance of all previous motor BHAs led to identifying the main challenges. Detailed modeling was then performed, involving well trajectory design, BHA design optimization, hydraulics modeling, and torque and drag modeling. The modeling included static simulation as well as drillstring vibrations using finite element analysis (FEA) dynamic simulation. This extended engineering analysis improved the bit and BHA selection capability. Several drill bits and BHA options were modeled and simulated under different drilling conditions to determine the most stable configuration. Simultaneously through the dynamics simulation, a stable drilling parameters plan was generated to improve the drilling performance. The modeling results indicated that the lighter BHA configuration minimized BHA - formation contact area, allowing for smoother and efficient weight transfer downhole. A reduction in BHA vibration produced a step improvement in ROP and drilling performance. The engineering modeling results were implemented by replacing the previously used motor BHA drill collars with heavy-weight drillpipe and smaller size jars. This hardware change resulted in an unprecedented cost reduction, a 52% improvement over the previous motor BHA in delivering the challenging section, achieving multiple additional records, and 56% ROP improvement over the field. This paper will present the design process and the detailed results for each run. Recommendations will be provided on how this process can be applied to increase ROP performance and reduce the cost per foot for such drilling applications.
In the past year, a client in the Arabian Gulf has been increasing appraisal and development well activity from the same slot to reduce the uncertainty of reservoir depth, identify oil-water contact, and determine reservoir production strategy. The operator has been addressing these issues by drilling pilot sections from planned development wells, then plugging and abandoning the section prior to drilling the production lateral. The sidetracking operation is then performed from the previous casing shoe, aided by cement plug and landed to the required horizontal depth provided by the data from pilot section. Conventionally, positive displacement motors (PDM) have been used to perform the sidetrack effectively, then followed by a rotary steerable system (RSS) in the bottom hole assembly (BHA) combined with near-bit logging-while-drilling (LWD) tools to land the well. Because the pilot section is often drilled with water-based mud and penetrates through multiple layers of unstable shales and the reservoir, the hole condition normally deteriorates especially after extensive wireline logging runs, even after the cement plug has been set. In collaboration with other service providers such as cementing and wireline, the directional service provider revisits the sidetracking procedures to improve the sidetrack operation and reduce overall well construction time. Combining extensive data otherwise kept within each service provider's domain, the directional service provider analyzes the hole condition specific to each pilot section using formation evaluation data, wireline caliper logs, and pilot section drilling mechanics data to determine the sidetrack depth, drilling parameters, cement plug type, and the optimized RSS and BHA to perform the sidetrack efficiently. This detailed sidetracking procedure is then shared to all concerned parties, including to clients at the wellsite and in the office, and other service providers for discussion to align all objectives and ensure the sidetracking operation will be efficient. In 2018, the operator implemented the sidetracking procedures on 9 wells and achieved 100% success for drilling sidetrack from shoe-to-shoe in a single run. The detailed procedures mitigated the risks of using an RSS and subsequently eliminated the need to run a PDM to initiate the sidetracks. Comparative to sidetracks performed by the PDM, the sidetracking procedure using the RSS BHA managed to reduce drilling time on average of 1 day per well. The RSS BHAs also improved the hole condition for the subsequent activities of the well construction cycle, leading to less casing running issues and improved torque and drag for subsequent sections.
Typical well surveys are made once per stand, producing a 95-ft survey database; however, numerous things can take place in that 95 ft of pipe. Small changes in continuous inclination and azimuth lay hidden between traditional static survey stations. Processing these real-time measurements, in combination with traditional surveys, generates a definitive 10-ft survey list, resulting in an enhanced geometrical representation of the wellbore position. This enhanced wellbore positioning becomes increasingly significant in areas with high-anticollision risk. This type of survey processing was implemented in extended-reach drilling (ERD) projects in the Middle East. A comparison between the 95-ft surveys and the processed high-resolution surveys showed changes to 10 ft in the true vertical depth (TVD) measurements. Such shift in the TVD is important because it can result in having to revise planned trajectories to further minimize anticollision risk arising from the nearby TVD proximity with offset wells. This paper will present data to quantify the enhancement in TVD positioning using advanced survey processing in ERD projects in the Middle East, and its impact on minimizing anticollision risk.
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