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The growth and evolution of offshore drilling units have gone from an experiment in the 1940s and 1950s with high hopes but unknown outcome to the extremely sophisticated, high-end technology and highly capable units of the 1990s and 2000s. In less than 50 years, the industry progressed from drilling in a few feet of water depth with untested equipment and procedures to the capability of drilling in more than 10,000 ft of water depth with well-conceived and highly complex units. These advances are a testament to the industry and its technical capabilities driven by the vision and courage of its engineers, crews, and management. From an all-American start to its present worldwide, multinational involvement, anyone involved can be proud to be called a "driller." Since the beginning in the mid-1800s until today, the drilling business commercially has been very cyclic. It has been and still is truly a roller-coaster ride, with rigs being built at premium prices in good economic times and ...
Considering the many complex factors involved in successfully operating a mobile offshore drilling unit, one may ask, "How do I pick the right drilling rig for the job?" The answer is that often there is more than one rig type that technically can do the job. A review of related topics will show many items that must be considered. First and foremost, the operator must take the time and effort to be knowledgeable about mobile offshore drilling units (MODUs), drilling contractors, the equipment involved, and the relationship between all the parties (operator, drilling contractor, and third parties). Surprisingly, this does not always occur.
As the name indicates, this type of rig is located on a fixed structure previously installed at the well location. The structure may be a fixed jacketed platform, spar, tension leg platform (TLP), or gravity structure; whatever it is, the rig sits atop it. Fixed platforms may have as few as 3, or more than 50 well conductors. Generally, the drilling rig is not a permanent part of the fixed structure. However, on some occasions, the unit is left on the platform for future workovers or additional drilling, if removing it is uneconomical.
The jackup-type mobile offshore drilling unit (MODU) has become the premier bottom-founded drilling unit, displacing submersibles and most platform units. The primary advantage of the jackup design is that it offers a steady and relatively motion-free platform in the drilling position and mobilizes relatively quickly and easily. Although they originally were designed to operate in very shallow water, some newer units, such as the "ultra-harsh environment" Maersk MSC C170-150 MC, are huge (Figure 1) and can be operated in 550 ft in the GOM. This type of unit can be commercially competitive only in the North Sea and in very special situations. Figure 1--Maersk's giant jackup (largest in the world) designed for deepwater use (550 ft in the GOM) and harsh North Sea environment.
Tender Assist Drilling (TADs) units are drilling units constantly challenging the status quo in drilling. By being in a red ocean market, Tender Assisted had to always find its way to evolve to deliver cost efficient drilling and well intervention solution for the operators. They are focussing mainly on two areas of activity: factory drilling of marginal field and Deepwater Drilling, however due to its flexibility, tender assisted is being considered for various other application. Marginal oil and gas reservoir requires drilling efficiency and an optimisation of any associated costs. The drilling package are fit-for-purpose and optimized for rig move and skidding and are generally opperated by experienced crews who developed themselves on this type of unit.
A long lock down and remote working period due to the pandemic has settled virtual meetings as the new normal, and after a year of this setting, we all have already mastered a variety of virtual platforms. Teams and Zoom, along with Webex and GotoMeeting among others are no secrets to us, and we feel kind of empowered changing our virtual backgrounds or telling others the top warning of 2020: "You are muted." But we must confess virtual meetings can get boring. When you are the leader or speaker in a meeting, you have a special responsibility, and it is up to you to maintain the level of attention high. If that was difficult in the real world, in the virtual one, it is beyond challenging and tricky because there are no fixed recipes.
Cheng, Zhong (CNOOC Ener Tech-Drilling &Production Co.) | Xu, Rongqiang (CNOOC Ener Tech-Drilling &Production Co.) | Chen, Jianbing (CNOOC Ener Tech-Drilling &Production Co.) | Li, Ning (CNOOC Ener Tech-Drilling &Production Co.) | Yu, Xiaolong (CNOOC Ener Tech-Drilling &Production Co.) | Ding, Xiangxiang (CNOOC Ener Tech-Drilling &Production Co.) | Cao, Jie (Xi'an Shiyou University)
Abstract Digital oil and gas field is an overly complex integrated information system, and with the continuous expansion of business scale and needs, oil companies will constantly raise more new and higher requirements for digital transformation. In the previous system construction, we adopted multi-phase, multi-vendor, multi-technology and multi-method, resulting in the problem of data silos and fragmentation. The result of the data management problems is that decisions are often made using incomplete information. Even when the desired data is accessible, requirements for gathering and formatting it may limit the amount of analysis performed before a timely decision must be made. Therefore, through the use of advanced computer technologies such as big data, cloud computing and IOT (internet of things), it has become our current goal to build an integrated data integration platform and provide unified data services to improve the company's bottom line. As part of the digital oilfield, offshore drilling operations is one of the potential areas where data processing and advanced analytics technology can be used to increase revenue, lower costs, and reduce risks. Building a data mining and analytics engine that uses multiple drilling data is a difficult challenge. The workflow of data processing and the timeliness of the analysis are major considerations for developing a data service solution. Most of the current analytical engines require more than one tool to have a complete system. Therefore, adopting an integrated system that combines all required tools will significantly help an organization to address the above challenges in a timely manner. This paper serves to provide a technical overview of the offshore drilling data service system currently developed and deployed. The data service system consists of four subsystems. They are the static data management system including structured data (job report) and unstructured data (design documentation and research report), the real-time data management system, the third-party software data management system integrating major industry software databases, and the cloud-based data visual application system providing dynamic analysis results to achieve timely optimization of the operations. Through a unified logical data model, it can realize the quick access to the third-party software data and application support; These subsystems are fully integrated and interact with each other to function as microservices, providing a one-stop solution for real-time drilling optimization and monitoring. This data service system has become a powerful decision support tool for the drilling operations team. The learned lessons and gained experiences from the system services presented here provide valuable guidance for future demands E&P and the industrial revolution.
Samuel, Orient Balbir (PETRONAS Carigali Sdn. Bhd.) | Chandrakant, Ashvin Avalani (PETRONAS Carigali Sdn. Bhd.) | Salleh, Fairus Azwardy (PETRONAS Carigali Sdn. Bhd.) | Jamil, Ahsan (Baker Hughes) | Ibrahim, Zulkifli (Baker Hughes) | Ivey, Alan (Baker Hughes)
Abstract Field D is a mature offshore field located in East Malaysia. A geologically complex field having multiple-stacked reservoirs with lateral and vertical faulted compartments & uncertainty in reservoir connectivity posed a great challenge to improve recovery from the field. Severe pressure depletion below bubble point and unconstrained production from gas cap had contributed to premature shut-ins of more than 50% of strings. As of Dec 2019, the field has produced at a RF less than 20%. Initial wells design consisted of conventional dual strings & straddle packers with sliding sleeves (SSD). Field development team was challenged for a revamp on completion design to enhance economic life of the depleting field. In 2015, as part of Phase-1 development campaign, nine wells including four water injectors were completed initiating secondary recovery through water flood. An approach of Smart completion comprising of permanent downhole monitoring system (PDHMS) and hydraulic controlled downhole chokes or commonly known as flow control valve (FCV) was adopted in all the wells in order to optimize recovery from the field and step towards intervention-less solutions. Seeing the benefits of intelligent completion in Phase-1, Phase-2, drilled and completed in 2019 – 2020 has been equipped with new technology "All-electric Intelligent Completion System" in 4 out of 8 oil producers. The new design addresses the reservoir complexity, formation pressure and production challenges and substantial cost optimization, phasing out the load of high OPEX to CAPEX. Installation of "All-electric Intelligent Completion System" has proven to be an efficient system compared to hydraulic smart completions system. It requires 50% to 75% less installation time per zone and downhole FCV shifting time is less than five minutes compared to several hours full cycle for hydraulic system. The new system has capability to complete up to 27 zones per well with single cable. It gave more options and flexibility in order to selectively complete more zones compared to hydraulic FCVs which requires individual control line for each zone. Future behind casing opportunities (BCO) have been addressed upfront, saving millions of future investment on rig-less intervention. In addition to that, non-associated gas (NAG) zones have been completed to initiate in-situ gaslift as and when required avoiding the dependency on aging gaslift facility. The scope of the paper is to show case the well design evolution during Field D development and highlight on how smart completion has evolved from original dual completion to hydraulic smart and recently to electric smart system, how it has contributed to cost and production optimization during installation and production life and also support the gradual digitalization of the Field D. In the end it demonstrates the optimized completion design to enhance the overall economic life of the depleting field.
Bimastianto, Paulinus (ADNOC Offshore) | AlSaadi, Hamdan (ADNOC Offshore) | Khambete, Shreepad (ADNOC Offshore) | Cotten, Michael (ADNOC Offshore) | Couzigou, Erwan (ADNOC Offshore) | Al-Marzouqi, Adel (ADNOC Offshore) | Chevallier, Bertrand (Schlumberger) | Qadir, Ahsan (Schlumberger) | Pausin, Wiliem (Schlumberger)
Abstract Majority of organizations endeavor to reduce operating costs and improve operational efficiencies. The concept of Mechanical Specific Energy (MSE) has long been implemented in the industry to improve drilling performance. The Drilling Real time Operations Center (RTOC) has taken the concept of MSE beyond its traditional approach by developing a Drilling Performance Measure combining data science and statistics to benchmark drilling efficiency. To extract maximum value from the available database, a workflow was developed to construct a Drilling Efficiency Benchmarking Tool. The different steps will be described for performing the data ingestion, cleansing, selection (offset well selection), methodology of computing the statistical model for MSE baseline per Formations and visualization of the output (charts and logs), to compare the actual MSE with baseline and thereby measuring the performance efficiency. The offset wells analysis results show that the workflow can construct an MSE baseline using high frequency data in a meaningful way, which is then set as a target envelope and projected through the real-time platform for monitoring and intervention purposes. This implementation of real-time MSE benchmarking helps identify the area of potential improvement, optimize drilling parameters to ultimately improve ROP and minimize lost time. As an analytical tool, it highlights achievable performance for each field and provide insights to consider new Best Practices.
Abstract A deviated newly drilled gas well in Western Caspian Sea in Azerbaijan, with a flowing water reservoir pressure of 17,500-psi and a flowing gas reservoir pressure of 12,200-psi was unable to regain flow after an unsuccessful attempt to bullhead produced water back into the well. During the bullheading operation, there was a peak registered pumping pressure of 12,933-psi without admission of fluid into formation. Producing interval was 5880mTVD with a MASP of 9,700-psi for gas reservoir. Coiled Tubing was the most viable option to identify the problem, to solve it and to regain access to the lower completion and then proceed with interval abandonment program. This being an unconventional well in multiple aspects, presented serious challenges accentuated in Safety, Well Integrity Control, Obstruction Removal, and Well Conditioning Plan Forward. Integrity of completion was believed to be compromised by the high pumping pressures applied during bullheading and a confirmed communication between production tubing and "A annulus". After performing 2 rig site visits, an action plan was issued to adjust the platform for a Coiled Tubing intervention for the first time. Points to be developed in the plan were HSE, Structural Analysis and modifications required for proper equipment accommodation. For well integrity control, it was imperative to evaluate the potential scenarios which could have led to the problematic well status. Completion history and specifications were reviewed to assure each of the potential operating scenarios could be controlled without compromising well integrity. On obstruction removal, simulation software was used to design procedure with optimum string, chemicals, rates and fluids to be used for the operation and which contingency fluids considered to be available offshore. It is challenging to perform effective cleanouts in completions with 2 different sizes of tubings (IDs 3.74" & 2.2") combined with restrictions (1.92" nipple), the success is a function of overcoming limited fluid pumping rates, slow annular velocities, particle sizes, cleaning speeds, among others. Well conditioning for future completion operations was planned depending on successful achievements of the coiled tubing intervention. A total of 14 runs with coiled tubing using different BHA configurations were performed to complete the scope. Well was safely and successfully cleaned from a starting depth of 2,512mMD to a target depth of 5,864mMD (5,610mTVD) by removing mud deposits, consolidated sand bridges and completion restrictions. Throughout the cleanout operation, best practices discussed on planning stage were applied to remove multiple obstructions encountered and dealing with potential corkscrewed casing. By accomplishing the well delivery, it is evident that the methodology followed during the planning stage and execution, was crucial to save the well from being lost or abandoned. There was an uncertainty whether the completion integrity was compromised by the high pressures used during the bullheading operation. Novelty in this intervention was the methodology for the risk assessment for an unconventional live well intervention with a 17,500-psi BHP, unseen pressure in the region. Thorough structural analysis was performed to assure the coiled tubing equipment could be placed safely on the platform to condition the well to regain production