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Reamers are an integral part of deepwater Gulf of Mexico (GOM) drilling and their performance significantly impacts the economics of well construction. This paper presents a novel programmatic approach to model rate of penetration (ROP) for reamers and improve drilling efficiency. Three field implementations demonstrate value added by the reamer drilling optimization (RDO) methodology.
Facilitated by user interface panels, the RDO workflow consists of surface and downhole drilling data filtering and visualization, detection of rock formation boundaries, frictional torque (FTRQ) and aggressiveness estimation, ROP modeling with analytical equations and machine learning (ML) algorithms [regression, random forests, support vector machines (SVMs), and neural networks], and optimization of drilling parameters. ROP model coefficients and bit and reamer aggressiveness are dependent on lithology and computed from offset well data. Subsequently, when planning a nearby well, bottomhole assembly (BHA) designs are evaluated on the basis of drilling performance and weight and torque distributions between cutting structures to avoid early reamer wear and dysfunctions. Geometric programming establishes optimal drilling parameter roadmaps according to operational limits, downhole tool ratings, rig equipment power constraints, and adequate hole cleaning.
Separate ROP models are trained for reamer-controlled and bit-controlled ROP zones, defined by the proportion of surface weight on bit (WOB) applied at the reamer, in every rock formation. This novel concept enables ROP prediction with the appropriate model for each well segment depending on which cutting structure limits drilling speed. In the first of the three RDO applications with field data from deepwater GOM wells, optimal bit-reamer distances are determined by analyzing reamer weight load in uniform salt sections. Next, ROP modeling for the addition or removal of a reamer from the BHA is used in contrasting well designs to conceivably alleviate a USD 16 million casing inventory surplus. Finally, active optimization constraints are investigated to reveal drilling performance limiters, justifying equipment upgrades for a future deepwater GOM well.
The proposed innovative workflow and methodology apply to any drilling optimization scenario. They benefit the practicing engineer interested in drilling performance optimization by providing insights on how different cutting structure sizes affect ROP behavior and ultimately aiding in the selection of appropriate bit and reamer diameters and optimal operational parameters.
Simultaneous hole opening with bit and reamer, based on acknowledged benefits, has become an drilling industry mainstay. Considering Bottom Hole Assembly (BHA) design and compliance requirements, bit and reamer in BHA, and issues with drilling parameters management, the operation presents severe drilling dynamics challenges. Additionally, several other factors initiate, sustain, and/or amplify dynamic dysfunctions. In their totality, these factors and conditions compromise hole opening efficiency, leading to increased cycle times and higher operational costs.
Current hole opening solutions and strategies have yielded inconsistent performances. Consequently, appropriate and effective solutions are needed to address above listed challenges. Data analysis must help identify factors and/or conditions that influence performance. These revelations must drive holistic solution approach for hole opening, that will be more effective at cycle time reduction, leading to project costs reductions. These expectations are only achievable, when appropriate implications are derived from effective interpretations of bit and reamer dulls. This paper will highlight and support these considerations with relevant field data, that focuses on hole opening efficiency factors, particularly dynamic dysfunctions. Cycle time effects and project costs considerations, as they relate to hole opening performance in challenging drilling environments will also be discussed.
This work presents the lessons learned from the studies carried out to understand the non-fulfillment of the hydraulic isolation required during the liner 10 ¾" cement job. Analyzing the drilling parameters performed and the events of cementing, it is possible that the stationary solids bed and the consequent poor conditioning of the well were probably responsibles for the failure to obtain the hydraulic isolation required for the cementing operation. The investigation report recommends some good practices for avoiding and/ or removing the cuttings-bed. The results of some simulations carried out during the investigation studies showed that drillpipe rotation speed contributes significantly to reduce the cuttings-bed height. Additionally to the extended reach, the well studied is a design well, has a complex trajectory, and the computer simulations revealed that ROP control is mandatory to obtain a proper hole cleaning and well conditioning. It was identified that the reduction of the hole diameter has a huge impact on well conditioning, drilling fluid displacement and cement slurry displacement. At last, the paper presents some recommendations for backreaming, mainly for evaluation of ideal operational parameters; adjust the drilling rates according to the hydraulic simulation, to ensure the hole cleaning and optimize the total time of the drilling intervention.
Silva, Leonardo Pacheco da (Petrobras) | da Mata, Pedro Oliveira (Petrobras) | Oliveira, Raphael Cristiano (Schlumberger) | Almeida Junior, Carlos Alberto (Schlumberger) | Benitez Matamoros, Alina Meylin (Schlumberger) | Florido, Jorge de Carvalho Lopes (Schlumberger)
This paper will describe the improvement made to the reamer cutter blocks to enhance its durability and optimize the Pre-salt Well Construction
Currently, most of the Brazilian's Pre-Salt wells have the last phase built-in 12.25in. In some situations, it is necessary to drill oil wells in a giant offshore field wells with five phases, enlarging the third phase from 18.125in to 22in. The high abrasiveness encountered at this phase increased the number of runs needed to drill it and, consequently, time and costs that encouraged the development of solutions.
This work relates what has been observed during the last years about reaming difficulties, specifically, in the enlargement from 18.125in to 22in when facing abrasive formations. Petrobras specialists analyzed these events and concluded the matrix of the reamer's cutter blocks was wearing faster and losing the capacity to hold the PDC cutters. The hole enlargement company, that Petrobras works for nowadays, developed a process that increased the resistance of the cutter blocks by increasing the hardness of the surface material prior to the brazing of the cutters. Then, Petrobras has had the opportunity to use both modified and common cutter blocks in a challenging operation to compare their durability and the results were completely satisfactory. The modified cutter blocks had much less wearing on the same formations. Based on this operation, we can conclude this process is validated since improved the reamer cutter blocks quality and its lifetime.
This paper can serve as a guide to reduce operations costs and to optimize well construction when there are concrete possibilities to enlarge abrasive formations.
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.