Sharma, Deepak (Cairn Oil & Gas, Vedanta Ltd.) | Golwalkar, Anirudh (Cairn Oil & Gas, Vedanta Ltd.) | Singh, Ankit (Cairn Oil & Gas, Vedanta Ltd.) | Doodraj, Sunil (Cairn Oil & Gas, Vedanta Ltd.) | Vermani, Sanjeev (Cairn Oil & Gas, Vedanta Ltd.)
The scope of the paper is to explain, at first, the modification done to the conductor deck of a jack up rig in order to drill two exploration wells from one open water location, offshore of east coast of India. Further the paper explains the process of batch drilling used in the campaign and how the combination of the two resulted in substantial cost saving.
For the modification in conductor deck, feasibilities were checked for each rig during the tender evaluation stage to create an additional slot in the conductor deck while maintaining the conductor tensioning requirement on both slots. The conductor deck of the finalized rig was fabricated accordingly. The wells were planned, with one being vertical and the other deviated, to two different targets. The conductors on both wells were batch set. Similarly, the surface hole sections on both the wells were batch drilled & cased. Then drilling of the production holes, logging & abandonment were carried out batchwise.
As a result of batch drilling, the time in installation & removal of wellhead was completely saved as it was carried out offline. Similarly the time in installation & removal of BOP was reduced to half as it was done only once. There were other instances as well, described in detail in the paper, which led to a cumulative savings of 29.86 days against total planned time of 96.51 days during the complete drilling campaign, apart from saving days & associated weather risk by eliminating one complete rig move. Much of the time saved above was due to the batch drilling which was a result of the conductor deck modification and also due to the well design changes based on actual well conditions, which are also explained briefly in the paper.
As industry is recovering from a steep decline in drilling activity, it is only incremental innovations & even more so, a combination of existing innovations like the one showcased in this paper, which can lead to a positive economics for E&P companies, especially for exploration drilling projects.
Gupta, Arpit (Weatherford Oil Tools M.E. Ltd) | Thomas, Emil (Weatherford Oil Tools M.E. Ltd) | Tomar, Gaurav (Cairn, Oil & Gas Vertical of Vedanta Limited) | Rawat, Ishita (Cairn, Oil & Gas Vertical of Vedanta Limited) | Prakash, Aditya (Cairn, Oil & Gas Vertical of Vedanta Limited) | Golwalkar, Anirudh (Cairn, Oil & Gas Vertical of Vedanta Limited) | Vermani, Sanjeev (Cairn, Oil & Gas Vertical of Vedanta Limited)
In offshore platforms, with high well density, slot recovery technique is an efficient way to target new / un-swept avenues to boost the production levels in a mature field. This leads to utilization of an appreciable length of parent bore which is an advantage to the operators globally in terms of surface facility retention and associated rig time saved. This paper discusses an actual case-study wherein dual casing exit was achieved in an offshore platform well resulting in significant time and cost savings.
For the subject well the subsurface targets were quite far from the mother-bore, resulting in a plan to side-track the well at a shallow depth where double casing existed, i.e. 9-5/8″ × 13-3/8″. The options available were pilot milling and dual exit using whipstock. Unlike multi-casing exits, pilot milling is a time consuming method which requires multiple trips and involves large volume of metal swarf handling at surface. The CBL-VDL verified the presence of cement outside 9 5/8″ casing that further supported the case of dual casing exit operation. Consequently, associated risks were discussed and plans to mitigate the same were put in place.
Single-trip 8-1/2″ whipstock-milling system was used to cut a window suitable for running drilling BHAs, liner, and completion equipment. The 9-5/8″ × 13-3/8″ annulus was monitored during milling and FIT test to check for any pressure communications. For well control scenario, arrangements were made for connecting the annulus to the choke manifold to ensure a closed system and thereby have provision of circulating through choke in case of gas migration in the 9-5/8″ × 13-3/8″ annulus. The window milling operation was done using sea water & intermittent Hi-vis sweeps. The window was milled successfully in a "single trip", thereby saving considerable rig time. No excess drag or held-up was observed and gauge loss on mills when pulled out of the hole was negligible. Well integrity was intact with no pressure communication in the annulus. The job was a successful one that led to finishing the well within the planned time and thereby, led to timely release of the jack up rig before the onset of adverse weather conditions.
Multi-casing exit technology in two or three casing strings opens the multi-level advantages to well intervention techniques especially in situations where the wells are old with limited access due to presence of fish or other restrictions that makes the deeper section of the well non-usable. Such sections can be avoided by sidetracking at a shallow depth and also provides an opportunity to access targets that are quite far from the original mother-bore.
Tangen, Geir Ivan (Lundin Norway AS) | Smaaskjaer, Geir (Lundin Norway AS) | Bergseth, Einar (Lundin Norway AS) | Clark, Andy (Lundin Norway AS) | Fossli, Børre (Enhanced Drilling AS) | Claudey, Eric (Enhanced Drilling AS) | Qiang, Zhizhuang (Enhanced Drilling AS)
In 2015, while coring in the carbonate reservoir in the second appraisal well on an oil and gas discovery in the Barents Sea (386 m water depth), the drill string fell 2 meters and a total mud loss was experienced leading to a well control incident. As a result, since 2016, the operator has introduced and used the Controlled Mud Level (CML) system. To date this system has been used on seven wells including two further appraisal wells on the same field and five exploration wells in the area.
In 2017 it was decided to drill a horizontal well in the same carbonate reservoir and to perform an extended production test in close proximity to the original loss well. Since it is not possible to predict where large voids (karsts) and natural fractures could be encountered, contingency to handle high losses, had to be implemented for the horizontal well. During the well planning, further risk reducing measures were implemented, including the use of wired drill pipe to improve the management of the wellbore pressure profile. This paper describes the planning processes leading up to the operation and the highlights of the operation itself together with the lessons learned. It elaborates on how wired pipe, used in combination with the CML system, added value to the operation. It shows how it was possible to drill the reservoir section with a low overbalance while managing severe losses associated with open karsts and natural fractures and still maintaining the fluid barrier. Despite the severe losses encountered it was possible to safely drill and complete the well without any well control event by use of the CML system.
This paper presents design, testing, installation, and lessons learned with the world's first completely integrated managed pressure drilling (MPD) control system on a deepwater drilling rig. While previous MPD installations have included driller-operated systems, they all include additional human machine interfaces (HMI) and standalone control network components with limited use of rig data and limited to no interfaces to other critical drilling machines on the drilling rig. For the installation described in this paper, all MPD control functions were permanently installed on the main drilling control network of the drilling unit, providing direct access to high speed data from other drilling machines that influence the wellbore pressure. This includes the rig's mud pumps, top drive, and drawworks. Moreover, the MPD control system has the ability to actively control the drilling machines, thereby optimizing performance through coordinated control of mud pump, top drive, and MPD chokes during drilling and connections.
Drilling operations are faced with conditions of subsurface uncertainty with unexpected drilling hazard potential. Operation is done in 24 hours a day continuously, until drilling is declared complete. The consequence of this work environment is the potential for high work accident, one of which is caused by situational conditions in the field that allow the communication limitations in clear and detailed.
Such conditions may include high-noise working conditions, limited visibility due to weather hazards (rain, fog, dark / night), and sour gas exposure. In this condition, often verbal communication is followed by non verbal communication, either in the form of the use of horns (morse), flag raising (semaphore) and limb movements. Non-verbal communication will be more urgent if the drilling operation conditions in emergency conditions, such as the occurrence of kick, blowout and exposure to sour gases. Non-verbal communication occasionally used in any drilling site does not have standardization, thus increasing the potential for communication errors.
Methods Non-verbal instructions intended in this paper is a sign language that serves as a medium for delivering work orders (instructions). This non verbal instruction uses one limb, represented by at least 2 limb movements in at least 2 stages of movement, to interpret a command or work instruction. If less than 2 movements or less than 1 stage of movement, then the movement of the body may have meaning, but can not be implemented because the instructions are not complete
With the invention, paper and efforts of this standardization, the communication process and the delivery of orders in both normal and emergency conditions at the drilling sites can be carried out in a structured, standardized, clear, detailed and widely applicable manner. The instruction method in the form of non-verbal codes is named: NS Blind Code Drilling, which has been registered since December 2014 to the Directorate General of Intellectual Property Rights and is in process related to the patent application.
The accurate makeup of Rotary Shouldered Connections (RSC) is a critical step in optimizing the connection lifetime under complex downhole conditions. The makeup torque value of RSC depends on the friction coefficient of the assembly and the lubricant, which cannot normally be individually measured or determined, so that the API RP7G gives a recommended makeup torque based upon an assumed, yet constant, friction coefficient while a certain safety margin is considered. Therefore, the field induced stress state of the connection may differ from the connection optimum torque under reference conditions. This will lead to the following consequences: the lifetime of each connection is not maximized based on its drillstring position and the torque and axial force that can be transferred through the connection is different from the technical maximum limit.
Due to the technological development, a wide spectrum of power tongs can accommodate the increasing interest in mechanized operations at the rig floor today. The importance of a torque-turn recording was stated in many papers as a good control method of the makeup process, especially for casing running applications. However, we believe that the reliability of a drill string can be improved by using feed back of torque turn recordings. State-of-the-art devices not only allow the precise mechanized makeup of connections, but they also provide sufficient data to analyze the quality of the connection make-up. The motivation behind the research is the desire to make use of the data that is already provided for the benefit of increased lifetime of the connections and the reduction of drill string failures, especially for drilling under extreme downhole conditions like long horizontal, HPHT or deep water.
This paper presents a short overview of the state-of-the-art of current technology followed by a discussion of how technological advances can be used to improve the drill string reliability. Also, the readers are challenged to find the answer to the title question: "Do we need an Intelligent Makeup Solution for Rotary Shouldered Connections?"
In recent years, an industry-wide demand for increased drilling efficiency has led to the development of technologies and methods focused on multi-well pad development and the minimization of the transportation of drilling rigs between locations. Studies have indicated the potential for improving drilling cycle efficiency through improvements in rig design and procedural documentation but have given limited consideration to the unitization and mobilization practices surrounding ancillary components such as mud pumps, light plants, bulk fluid storage and other systems that comprise modern land rigs. This study examines current unitization practices, as well as offers alternative methods of integrating ancillary system components to improve current transport configurations. Specifically, ancillary systems whose transport dimensions and weight exceed the federal and state requirements for commercial vehicles operating within the National Highway Freight Network (NHFN).
In this study, the application of transport logistics software is used to demonstrate that there exists the potential for significant reduction in land rig mobilization costs through revised unitization of drilling rig ancillary systems. Permit data from proposed wells located in the Permian, Bakken, and Marcellus are utilized to develop transport scenarios whose focus is to quantify the impact of ancillary system unitization on the total fee structure associated with rig mobilization between geographical regions. Within each scenario, ancillary systems from currently active rigs are compiled and itemized according to their weight, transport dimensions, and degree of component unitization. The resulting schedule is then processed through transport logistics software to identify fee schedules associated with oversize permits, overweight permits, civilian and police escorts, driver rate/fuel costs, and associated service fees for the individual loads. Following the conclusions derived from the analysis of the existing rig systems, the series of transport scenarios are repeated using revised component configurations. The revised system employs a combination of divisible and non-divisible loads whose components are either integrated as part of dedicated transport trailers or located within ISO containers loaded onto commercially available transport trailers. The fee schedules from active rigs, as well as the results from the proposed unitization, are explored in detail to identify critical areas for improvement regarding unitization practices for active rigs and future builds.
Kumar, Abhineet (Cairn Oil & Gas, Vedanta Limited) | Prakash, Aditya (Cairn Oil & Gas, Vedanta Limited) | Singh, Alok (Cairn Oil & Gas, Vedanta Limited) | Bharati, Pradeep (Cairn Oil & Gas, Vedanta Limited) | Jayan, Binshu (Cairn Oil & Gas, Vedanta Limited) | Kothiyal, Manish (Cairn Oil & Gas, Vedanta Limited) | Patil, Bhushan (Cairn Oil & Gas, Vedanta Limited) | Sarma, Phanijyoti (Cairn Oil & Gas, Vedanta Limited)
An offshore drilling campaign comprising of four development wells was conducted to augment oil production from a field located off the western coast of India. All four wells were designed to be sidetracked from existing depleted wells of the field. Historically, preparing existing wells in the field for side-track took ~4 days/well of a drilling rig and associated spread cost. This paper presents a case- history of conducting side-track well preparatory activities by a rig-less well intervention spread leading to significant time and cost savings. This method was also the first instance of such an activity being conducted in an offshore environment in India.
Prior to actual side-track drilling from an existing well in a brown field, it is required to abandon the open zones in the existing well and prepare the well for casing window cutting for further drilling to a new sub-surface target. Typical preparation activities include multiple wireline runs to set/retrieve deep set and tubing hanger plugs, well killing, nipple-down X-mas tree, nipple-up BOP, wireline run to cut tubing, retrieval of existing completion and ultimately placement of cement plugs to abandon the parent wellbore. The routine approach in the organization for all previous offshore drilling campaigns was to utilize the offshore drilling rig for afore-mentioned well preparation activities. Substantial rig time was spent incurring the cost of entire rig spread for an average ~4 days/well equivalent to ~40% of total well completion time.
The paper elaborates on rig-less operations set-up consisting of Cementing and Wireline Units utilized to conduct well killing, placement of cement plugs, production tubing cutting and nippling down X-mas tree prior to the mobilization of the drilling rig at the platform. The only operation left for the drilling rig was to pull-out the existing completion string and then drilling operations could commence.
The execution of planned operations was flawless on three wells while one well posed technical limitation due to its high deviation. The rig less well preparation campaign was concluded incident free, ahead of schedule and within budget. This offline exercise prior to rig-move saved ~12 days of drilling campaign time which helped in cutting down on overall drilling campaign cost and also allowed the flexibility of adding more wells to the campaign within fair weather window.
While this was an effort to simplify operations and save costly drilling rig-time in a side-track drilling campaign by conducting some very critical operations offline, these methods can also be adopted for planning well abandonment and decommissioning activities in a mature field.
The last several years has seen an increasing trend toward more depleted reservoirs and more challenging wells with tighter mudweight windows. Managed Pressure Drilling has been employed in these challenging well conditions, however industry take up has been slow for a number of reasons including technical, economic and deployment related. Those wells that have utilized Managed Pressure Drilling have tended to focus on the drilling related aspects of well construction. However, other areas of well construction such as casing and liner running and cementing and completion installation are equally and in some cases even more technically challenging. One area that has potentially hindered the uptake of Managed Pressure Drilling is that in general, and in particular in the well construction operations outside of on bottom drilling there has been no access to real-time downhole data. In particular this is related to real-time pressure data. Whilst cementing, displacing or completing then multiple fluid types and densities may be circulating both inside and outside the drillpipe, leading to significant challenges in simulations and models derived from surface data. To overcome this a new acoustic telemetry and measurement network is being deployed in depleted reservoir and managed pressure drilling operations to provide real-time downhole and along string measurements of pressures, temperatures and weights. Real-time data case histories will be shown from the Gulf of Mexico and the North Sea illustrating how this is being used to drive real-time decisions during drilling, cementing and completion installation operations in tight margin windows, depleted reservoir conditions and under managed pressure drilling operations.
Baker Hughes drilled one horizontal well for major Indian operating company in a, low resistivity contrast field, onshore India. The candidate field / basin is a proved petroliferous basin, located in the northeastern corner of India.
The scope of work for this project involved integrating geological and open hole offset parameters to build a Geosteering model. Integrated data included a study of offset well data from the field, regional and local dip analysis from wellbore images, and a review of structural maps. Successful integration of these data helped to steer the well in the desired zone as per plan and make the best use of the data and to reduce uncertainties in Geosteering, drilling. Although high-quality 16-sector images commonly yield bedding dip, fracture and other geological information, this paper emphasizes how real-time reservoir navigation decisions was made using Geosteering modelling, real-time image processing, dip picking study etc.