Historically underreaming while drilling (UWD) operations were implemented in offshore field in Azerbaijan to decrease Equivalent Circulating Density (ECD) and have better hole quality for casing running. Lithology in this UWD, 8.5 × 10.25-inch section consists of sand and shales with 3-5kpsi Unconfined Compressive Strength (UCS). Well trajectory has planned dogleg severity up to 3-3.5 deg/30m. In such a condition underreaming operations are known to be more challenging and complex compared to conventional drilling with bit only. In the offset well, an operator had fatigue related twist off at the reamer's lower sub connection which contributed to 58 hours of NPT.
Our challenge was to come up with the root cause of the twist off and then suggest changes in BHA to avoid this and prove that the modified BHA performs as expected. Our finite element analysis (FEA) based 4D modeling software can identify different vibrations (axial, lateral, stick slip), bending stresses and bending moment of each component in the BHA. Using this software, we were able to come up with the root cause of the twist off, which was due to high bending stress.
In UWD there are two cutting structures in the BHA, so optimizing both cutting structures has a significant impact on the overall performance. Successful run key points are to analyze the underreamer placement in BHA, operating parameters selection for different scenarios (when both bit and undereamer are in the same rocks or when the bit is in soft and undereamer is in hard rock), lateral vibrations and whirling phenomenon which can potentially damage and develop fatigue on BHA components. Multiple BHA's were simulated and based on the results the most stable BHA was recommended for the upcoming well.
The operator implemented the recommended BHA and a total of 1200m was successfully drilled and opened in one run without any NPT. All directional requirements were achieved and both bit and underreamer came out in good condition which confirmed that the new optimized BHA was stable in the downhole drilling conditions. The liner was also run without any issue confirming the borehole quality.
This paper will review the results of analysis and how modeling prediction was validated in the field.
In Vietnam, there was a need of a lean surface casing due to restricted drift inside diameter (ID). The 2nd slot of the splitter conductor only have 13-1/2" ID max pass through. The practical option is to drill with 12-1/4" bit and open to 14-1/2" hole to set 11-3/4" casing OD. Similar reasoning for the intermediate hole that will require to under ream the hole from 10-5/8" bit to 12-1/4" hole and set 9-5/8" casing OD. Although these under reaming operations are commonly practiced, the technical limitations are still inefficient and compromising. Conventional reamers still have limited activation/deactivation cycle for operational flexibility and long rathole of the reamer to bit depth for casing shoe placement.
The long awaited technology is now available with the presence of intelligent reamers that have unlimited activation & deactivation cycles and can be placed directly above the rotary steerable system for shortest possible rathole. The setup is to combine two intelligent reamers in a single BHA. The 1st reamer placed strategically on top of the MWD & LWD tools while the 2nd reamer is directly above the rotary steerable system tool. As both reamers can be both activated and deactivated through downlinking, the reamer has to be activated simultaneously to control the risks associated with hole opening and LWD data acquisition. The 1st intelligent reamer will be activated first while drilling the section formation and the 2nd intelligent reamer will then be activated at section TD to ream and shorten the rathole. For the purpose of cleaning the hole effectively, both reamers can be deactivated to execute high flow and RPM without creating new cuttings from the reamer blades and avoid making a bigger hole at the low side.
This enabled shoe to shoe drilling while under reaming and achieving less than 10m rathole. These operational capabilities saved at least 50% of the section rig time compared to having a 2 trip system. Combination of reduced casing shoe rathole and open hole exposure mitigated the well bore instability risks and helps in managing mud weight for both hole section intervals. The unlimited activation cycle provided flexibility in operations particularly in dealing with hole cleaning and wiper trips. Plus, the intelligent reamer provides realtime reamer diameter which gives confidence on the drilled hole size for casing running preparation and decisions.
Intelligent reamers have unique tool features that differentiate from the rest of current industry technologies. This feature helps to eliminate the risk of under-reamer balling, which improve the rate of penetration. The success of the operation has spread throughout operators in Vietnam, and now the intelligent reamer is considered as a game changer application in drilling lean casing profiles.
In planning for their first TLP deep water project in Malaysia, Shell faced the unique challenge of drilling ERD wells in soft unconsolidated sands with narrow ECD margins. Prior experience suggested the benefit of managed pressure drilling & an additional casing profile with hole enlargement to be implemented for these wells. The formation is also believed to be time sensitive, and reducing the wellbore exposure time between drilling and running liner was considered a priority.
A full suite of LWD services were also planned to be run on these sections, resulting in potentially a very long rat hole as the conventional reamer can only be placed above LWD tools. An additional hole opening trip to minimize rat hole length was not desirable, which in turn leads to concerns of well bore stability due to time exposure as highlighted earlier, as well as increasing potential risk of side tracking in the soft interbedded formations. Flow rate restrictions due to the pressure drop requirements from conventional reamers, was not desirable so as to maintain ECD stability.
In order to address the needs and challenges above, contractor proposed a dual digital reamer solution, in order to ream and drill the hole sections in a single run. The digital reamers, each being powered by the LWD suite, were activated via downlinks, eliminating the lengthy time required by drop ball reamers at high angles. The ability to downlink on demand and perform selective reaming without any pressure drop restriction, had provided added benefits while drilling in narrow ECD margin. As placement of the digital reamers are flexible within the LWD tools, dual reamers were deployed in the BHA. The top reamer located above the LWD tools was activated while drilling to ensure necessary LWD data quality was obtained. A near bit digital reamer was activated post-drilling to eliminate the long drilling rat hole, resulting in minimal rat hole achieved similar to the outcomes of a dedicated trip. Eliminating the dedicated trip also greatly minimized the risk of unintentional side track.
The use of dual digital reamers enabled safe and problem-free drilling, logging, casing and cementing; allowing all of Shell’s objectives to be met in a single run, as well as significant exposure time of the wellbore, up to 3.5 days over 3 hole sections and costs savings, up to 1.2mil USD.
Deepwater wells routinely use concentric reaming devices in the bottomhole assembly (BHA) to lower the equivalent circulating density (ECD). In Gulf of Mexico (GOM) applications, concentric reamers are frequently used and are positioned approximately 100 to 150 feet behind the pilot bit to address formation evaluation and other operational constraints. This distance between a drill bit and the concentric reamer poses bit–reamer synchronization challenges, especially while drilling interbedded formations, where the bit could drill a softer formation while the reamer is placed in a harder formation or vice versa. This situation causes fluctuations in the compressive load at the bit and reamer. Cutting element damage often results from overloading, leading to a premature and costly trip. In many cases, the pilot bit or reamer could be deprived of the optimal compressive load to cut the formation, resulting in lower-than-expected penetration rates. Inadequate and fluctuating compressive loads at the bit or reamer often trigger unsustainable vibrations.
Efforts to address the bit-reamer matching issue are ongoing in the industry, and managing the aggressiveness of pilot bit and reamer is frequently used as a potential solution. Although modelling programs are extensively used during the well planning process, a lack of specific guidelines continues to exist in the industry.
Hybrid bits, which combine polycrystalline diamond compact (PDC) and tungsten carbide insert (TCI) rolling cutter elements, have been widely and successfully used in GOM. These bits offer higher drilling efficiency because of their dual cutting elements and balanced aggressiveness. The results of 18⅛-in. hybrid drill bit usage with a concentric reamer provided encouraging results and offered a potential solution to the bit-reamer synchronization issue.
Using real-time downhole data, this paper evaluates and compares bit and reamer load distribution, drilling mechanics of PDC and hybrid bits, and provides valuable analytical insights on successful application of hybrid bits to address the issue of bit-reamer synchronization.
Al-Otaibi, Yousef (Kuwait Oil Company) | Al-Mutawa, Majdi (Kuwait Oil Company) | Bloushi, Taha (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Sharma, Siddhartha (Kuwait Oil Company) | Pradhan, San Prasad (Kuwait Oil Company) | Manimaran, Palaniappan (Kuwait Oil Company)
Optimization of permanent liner completions in the North Kuwait Jurassic Gas (NKJG) reservoirs has been an ongoing challenge progressed on a steep learning curve within the last decade. Various completion options are field-tested in determining the optimal completion hardware and activation methodology. The asset's objectives have been multi-dimensional: preserve natural fractures, minimize formation damage, segregate, stimulate and activate optimally, while installing permanent completions hardware efficiently, which can withstand 15,000-psi differential pressure at high temperature and sour gas environment and sustain production for the well life of over 20 years.
NKJG faces the enormous task of increasing the hydrocarbon production potential by over 200% within a short time period. The reservoirs are high-pressured and high-temperature (HTHP) gas condensate assets with tight matrix properties (i.e. <0.1 mD permeability), in variation with naturally fractured sections within flow-zones separated into eight segments. Preserving the natural fractures, removal of near wellbore damage and segregating flow-zones based on lithology and critical reservoir properties are important especially in peripheral subsurface locations, where the realization of full reservoir potential is not only essential for production success, but also required for appraisal of boundary conditions. For realizing these objectives, the asset custom-designed a multi-stage completion system with hydro-mechanical liner hanger packer, open-hole packers, hydraulic anchor and multiple frac ports set and activated as a drop-ball system. Due to the high completion loads, differential body and packer rating are manufactured to 15,000 psi using corrosion resistant alloy throughout, with the PBR and seal-bore assembly designed to withstand differential pressures and contraction during multiple fracturing events.
Custom-designed multi-stage completion assembly (MSC-HP) was successfully installed, sequentially hydraulic-fracced and commingle-tested on flowback. Customized operational guidelines were established including a pre-set success criterion, openhole and caliper log sequences, tie-back cementation and subsequent clean out trips, followed by hole conditioning and reamer runs to compute the final drag and friction forces. Differential sticking risks were mitigated by avoiding the "pressure ramps" exacerbated by differential depletion evident in the area. Reservoir was segmented in three distinct intervals to maximize flow potential. As a result, the asset's objectives were successfully met, with the additional benefits of proving multiple zone activation, each with a complicated sequence of operational events, performed sequentially in four days.
This paper documents the project cycle from successful planning and design, to installation and execution phases of the MSC-HP in peripheral deep NKJG asset. Key learnings and critical factors, which led to the successful well results in spite of less favorable subsurface location are summarized. Added complications due to the severe NKJG specs will be discussed as the number of global analogues is scarce leading to limited opportunities for the industry to learn from in unconventional/conventional mix layered carbonates.
Trunk, Philip (Schlumberger) | Nasief, Mary (Schlumberger) | Shi, Kevin (Schlumberger) | Long, Wiley (Schlumberger) | Terracina, Dwayne (Schlumberger) | White, Allen (Schlumberger) | Tocantins, João Pedro (Schlumberger) | Costa, Edson (Schlumberger) | Louback, Leonardo (Schlumberger) | Hird, Jonathan (Schlumberger) | Aguiar, Romulo (Schlumberger)
The function of an underreamer is to enlarge an existing wellbore below frequently encountered restrictions such as drift diameter of casing or the wellhead (Figure 1). This can be done by underreaming while drilling (URWD), also known as hole enlargement while drilling (HEWD), where the reamer in the BHA enlarges the pilot hole created by the bit while the hole is being drilled.
Torsional instability in a drilling system is a significant challenge that limits performance. In its extreme form, known as stick-slip, the drillstring stops and restarts, exposing its downhole equipment to extreme forces that can lead to failures, unintended trips, and escalated operation costs. Torsional instability can also trigger lateral dysfunctions and whirl, creating further risk of bit and bottomhole assembly (BHA) failure. The risk of torsional dysfunction is heightened in applications involving concentric reamers and long drillstring, high-angle wells.
The correlation of polycrystalline diamond compact (PDC) bits with torsional dysfunction is well known, and different approaches have been suggested to address the issue. The fixed depth of cut control (DOCC) approach, which is commonly used to address the issue, limits the PDC bit and formation engagement at a pre-determined ratio of rate of penetration (ROP) and drillstring RPM. However, this approach has an uncertain success rate when drilling conditions change. To address the challenge of torsional dysfunction while drilling a directional well with a 12¼-in. pilot bit and a 14½-in. concentric reamer, a self-adaptive DOCC technology was deployed in a deepwater well in the Gulf of Mexico (GOM). The self-adaptive DOCC technology automatically adjusts the depth of cut engagement threshold as drilling conditions change, eliminating the manual parameter adjustment required at surface to manage torsional dysfunction.
The application of self-adaptive drill bit technology in the target well yielded excellent results, and the section was completed with a single bit/BHA run. Ninety-eight percent of the interval was drilled with no torsional dysfunction. The drillstring whirl was negligible, and 99% of the interval was drilled without lateral vibration. Eliminating harmful dynamic dysfunction significantly enhanced drilling performance and increased the ROP by 57% over the best PDC offset run. The dull bit condition was very encouraging; the bit displayed very low wear and no undesired impact damage, showing the effectiveness of the technology.
This paper uses real-time drilling dynamics field data measured downhole and demonstrates the effectiveness of self-adaptive DOCC technology for drilling performance improvement in deepwater directional well where torsional dysfunction continues to remain a significant challenge and could be a performance limiter.