Driving efficiency to ensure cost and risk reduction in well operations is paramount for any operating company; to achieve this, the main objective was to implement a continuous improvement process that measures performance to then improve it, acquiring lessons learned and finally implement new technologies to reduce non-productive time, invisible loss time and push the technical limit to the limit. The first step was to measure the current performance to determine average and best references to compare against. The drilling operations and engineering teams defined KPIs for each well type and respective sections and activities involving all levels of the organization including every individual, ensuring effective communication inclusive of Rig Crew and Service Providers. The initial KPIs were defined, discussed, validated and agreed by both operations and engineering management, all engineers were informed and challenged to measure their performance against KPIs. Once new records were achieved, a workflow to document best practices initiated, once identified, validated and documented, becoming the new standards. Similarly, once average performance was not achieved, a ‘Lessons Learned’ workflow was initiated. Aiming to get the team engaged a communication protocol of the Highlights and Lowlights was put in place, including recognition during operations meeting and emails. The primary results of the deployment of this initiative include the delivery of a 10% additional well count compared to the initial year's plan. An overall improvement of the overall Drilling and Completion Performance was also noted. An important improvement of the overall Rate of Penetration (ROP) was observed, as one of the key performance indicators. It was also notice a considerable reduction of the Flat time. New practices for losses mitigation in hazardous areas were stablished. The lower completion design was enhanced. The upper completion design and utilize Dual Hydraulic Packer in Oil producer well was optimized. Finally, the 1st Maximum Reservoir Contact Well was completed for two of the three Fields in the Team. The added value achieved by the implementation of these innovative practices includes the implementation of the KPI Gauges as a visual instrument to be used on daily operations meeting by the engineers and management, to quickly and effectively understand performance and improvement in multiple dimensions. Additionally, the implementation of a continuous improvement mind-set, focus in introducing changes gradually instead of radically to ensure a soft and solid adoption embraced by all team members. Finally, the improvement of the office-field communications, including a sense of ownership and achievement for each goal to achieve and record to break, to the point that every colleague involved in a specific operation, independently of their organization (Operator, Contractor or Service Company) is equally committed and engaged.
The paper explores the contributing factors impacting/constituting enhancement of the drilling in the 6' section in one of the giant offshore fields of ADNOC. While there is a tangible and obvious contribution from the surface manipulation of parameters, there is also an irrefutable connect between down hole factors and ROP. Factors such as formation density, porosity, Mechanical Specific Energy, Orientation, mud weight, DDI crestal or flank placement of the well and their impact on performance. The crestal wells have come with their own inherent downhole problems and challenges. While at times there is linearity between the formation Mechanical Specific Energy and formation Density, there isn't necessarily a linear relationship between the drilling parameters and the resultant ROP. The density and porosity of the formation not only impact the MSE but the ROP downhole as well. The required parameters to drill each formation also vary with these properties and their effectiveness can in turn be tracked with the MSE being seen as a direct result of the BHA and formation interaction. The analyses entailed cover the formation density, discrimination plots, Azimuth, mud weight, BHA stabilizations, MSE and the respective intra parameter interactions that form the overall resultant drilling performance.
Field Background In Aug. 2015, Umm Lulu drilling team drilled and completed well014 as a first linerless design by setting the 9 5/8" casing in Thamama-I formation and drilling an 8 ½" section till TD, relying on swell packer for zonal isolation. Post evaluation of UL-14 design found cross flow between Thamama-I formation and Thamama-II target reservoir. The drilling division developed another design by extending drilling the 12 ¼" hole till Thamama-I A base to isolate Thamama-I with cement after running the 9 5/8" casing and drilling 8 ½" hole till section TD. This scenario was not possible to execute due to the unavailability of completion equipment (4 ½" × 8 ½" swell packer). The drilling division thought out of the box to drill 6" hole directly from 9 5/8 casing to address the equipment availability constraint. This option was pursued after thorough evaluation of all potential challenges. In April 2017, well018, which was a first revised design, was drilled and completed successfully 10 days ahead of plan, saving $2.00M. In June 2017, well020 was delivered with the best jack up 10k duration in ADMA-OPCO (31.5 days) and the best single oil producer with lower completion duration of 56 days, saving more than 15 days and $3.2M.
After completing the drilling phase of the 8½″ section for a well in a giant mature field offshore Abu Dhabi, due to geomechanical challenges it was not possible to run the 7″ liner in a shale formation which was open for a long period of time due to rig repairs (top drive failure in open hole), exposing all reservoirs and compromising the field development strategy. After several unsuccessful attempts to run the liner and leaving a drilling BHA in the hole during one of the cleanout runs, it was decided to sidetrack around the fish to intersect the original 8½″ open hole section in order to recover the original hole and isolate the reservoir flow units from each other, which was critical for the field development since more than five reservoir layers were opened with water and oil bearings increasing the risk of damaging the reservoir integrity due to potential cross flow. Detailed measurement-while-drilling (MWD) survey analysis was conducted for the original hole in order to enhance surveys accuracy and minimize positional uncertainty. Typical survey management practices were implemented for Sag and Drilling String Interference; other techniques such as Dual Inclination, In-Field Referencing, and Multi Station Analysis were also applied. The implementation of these different survey management practices and their respective results are covered in detailed in the current article. Comprehensive planning was carried out, the sidetrack was accomplished and the original hole was successfully intersected at the first attempt. The advanced applied survey management techniques were crucial, particularly in the absence of magnetic ranging as the interval to intersect was open hole. The outcome of these corrections resulted in a shift of 8ft to the final well position, ensuring the correct direction and position for a successful attempt to intersect the well. This intersection was particularly challenging as the original hole had a 3D profile, thus it was critical to minimize both vertical and azimuthal uncertainties. Intersection was achieved with an RSS BHA, and the success of this intersection without magnetic ranging capability was only based on following a planned well trajectory that intersected the original hole surveys, clear validation of the accuracy of the surveys for both original and sidetrack holes. Achieving this challenging directional drilling goal allowed the completion of the well as per original plan, which was critical for the field development plan of these reservoirs. Based on the fact that there is very limited existing literature covering similar cases to the one presented, this current case represents a solid successful reference to be replicated in similar cases in the future covering these challenging applications of advanced survey management techniques.
Stuck pipe is one of the biggest challenges in the drilling sector and is a multi-billion-dollar issue. Recovering from stuck pipe absorbs significant cost and time. Durations for stuck pipe events and recovery can be mostly variable from a few days to up to over a month to resolve. When attempts to release the stuck pipe by jarring or acid fail, the operating company and drilling contractors are left with little option but to sever the drill string and prepare for side-track operations or even abandon the hole. Traditional pipe severance methods in the event of a stuck pipe situation typically take significant time (often days, and sometimes weeks), require specialist tools, Service Hands, and are usually reliant on wireline services to deliver the severance method. In 2018, a Major Operating Company in UAE faced a challenging high-sticking Formation, which caused massive NPT, stuck of drill strings, and loss of drilled section holes. Brainstorming within the Drilling Engineering team took the campaign to the next level of pre-planning to reach deep access in the hole to be able to achieve zonal isolation by spotting cement plugs through drilling BHA, find a solution to save the hole and recover the pipes in an efficient, cheap and productive manner. An environmentally safe pre-planned solution to severe the drill string was proposed to help save the wells and allow an excellent methodology to save the wells/fields from stuck pipe risks. The engineering solution allows a fast recovery of drill pipes using a downhole tool as a part of drilling BHA, with the option to activate it if required, by dropping a smart dart and circulating with mud for a specific time to apply cut string with two option, either spotting cement with recovered BHA or lift BHA with fish neck to try to fish in the hole.
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