Well known in the oil and gas industry is the importance of understanding drilling system vibrations and bit-reamer weight transfer when drilling with hole openers. A field testing program was carried out on a full-scale experimental test rig in the state of Oklahoma, USA, with known lithological formations, in order to evaluate underreaming system designs. In this context, the underreaming system comprised the bit, the drive system, and the underreaming element. To fully understand how the system interacts with the formation and reacts to inputs from the surface, drilling mechanics measurements were taken above and below the reamer element. Drilling dynamics measurements were also taken at three places in the BHA, with two drilling dynamics packages spaced out below the reamer and one positioned directly above it. That way, dynamics on the bit and reamer could be studied separately to understand how bit and reamer performance affect each other and the overall system dynamics. The first well was directionally drilled with a rotary steerable system, concentric reamer, and vibration monitoring equipment set up in an industry-standard arrangement. This paper will describe how the findings and learning from the initial field test led to bit redesign and operational techniques implemented to enhance the drilling system stability. Another borehole was then drilled through identical formations with this improved system, offering a unique detailed comparison between the two field tests. The new bit design allowed the bit to control the drilling rate with better weight distribution between bit and reamer, significantly reducing vibration, and in this study, without impacting penetration rate. A concentric reaming tool new to the drilling industry was used in both wells as a part of this study and will also be described. This tool demonstrated good steerability with a rotary steerable tool system and operated properly, drilling closed, activating, reaming, and finally, closing for retrieval from the hole. Introduction The purpose of this paper is to describe testing done under downhole-controlled conditions in identical, side-by-side wellbores with heavily instrumented BHAs. The testing compared the results of drilling with a conventional bit/reamer system compared to a specially designed pilot bit synchronized to the reamer. In both cases, the BHA was designed with dynamics modeling software with the objective of minimizing vibration. The test results proved a methodology that matched the reamer and pilot bit to substantially reduce vibration.

Technological improvements of drilling and reaming methods continue to be evaluated and introduced to the drilling industry. This paper describes recent, controlled testing of new expandable concentric stabilizers and reamers, performed on a full-scale, highly instrumented drill rig. An inherent problem of drilling and reaming concurrently is that conventional fixed stabilizers run above expandable reamers can be no larger than the pass-through diameter of the restriction above it and thus cannot effectively stabilize the upper BHA, which often results in undesirable vibrations. However, recent controlled tests have been conducted in twin wells drilled from the same casing under a full-scale drilling rig, one well with only a concentric expandable reamer and the other with both expandable stabilizer and reamer. The testing has shown that utilization of this novel stabilizer produces significant gains in performance. BHA modeling predicted lower bending moments above the reamer when a concentric stabilizer was utilized. The well drilled with the stabilizer above the reamer resulted in higher ROP with lower downhole WOB and up to 35% reduction in drilling mechanical specific energy (MSE), as compared to the well drilled without the expandable stabilizer. The stabilized well had significantly better drilling efficiency, which is attributed to reducing buckling and whirl in the drill pipe and upper BHA, and reduced frictional losses against the borehole wall. Additionally, lower levels of whirl, lateral and stick-slip vibrations were recorded with the new expandable stabilizer. The paper describes the novel design features of this expandable stabilizer, which are credited with the step-change improvement in drilling efficiency. Monetary savings from increased drilling efficiencies and improved reliability are anticipated for operators and will be discussed in this paper. Introduction The following three passages from previously written technical papers introduce the subject of this paper and the inherent problem of stabilizing the BHA and collars above the reamer in the enlarged borehole. "Historically, concentric underreaming has been plagued by several challenges. Some reamers, especially earlier models used after drilling a hole, were not rugged and failed downhole, leaving parts behind to fish out. Some current industry concentric reamers have complex functionality, requiring a fine balance of WOB, flow, and pressure drops in order to activate and operate properly. Some have multiple sliding mandrels with close tolerances that have problems closing after use due to accumulation of solids. Some reamers require lower flow rates while drilling out the casing plug and then a higher flow rate to activate the reamer, sometimes failing to open and remaining closed the entire run. Some reamers utilize hydraulic pistons for cutter blades that are difficult to close and pull into casing after drilling with water-based mud. These hydraulic reamers had problems with blades closing under reaming of high-angle holes due to weight of the BHA. Some of the reamers in the market have had small and less-effective cutter blocks that only allowed a few PDC cutters, reducing their life and cutting efficiency." (Radford et al. 2008)

Nowadays, one of the greatest deepwater drilling challenges is maximizing drilling efficiency while mitigating vibration dysfunctions when drilling and underreaming through salt and sub-salt formations. Historically, vibration has been responsible for considarable non-productive time (NPT) related to bottom hole assembly (BHA) twist-offs, downhole tool failures and premature bit and underreamer wear. With the high operating costs associated with deepwater sub-salt wells, operators have increased their focus on improving drilling efficiency by mitigating harmful vibration. For years, bits and underreamers were designed and selected independently, not as part of a system. This tradition has contributed to drilling dysfunctions that cannot be controlled by drilling parameter management that can potentially lead to drilling failures. Through advances in technology and drilling practices over the past two years, operators and service companies have realized that optimum synchronization between bit and underreamer is critical and one very effective way to achieve operators drilling efficiency objectives. This paper focuses on significant performance improvements achieved while drilling inter-bedded formations, salt and sub-salt sections in a deepwater well in the Gulf of Mexico Green Canyon area. In this case study, the operator deployed a concentric underreamer coupled with a fit-for-purpose bit, designed for this type of application. The proper selection of bit and underreamer and the implementation of drilling best practices allowed the operator to drill smoothly, limiting harmful vibration levels, even through lithology transition zones, including the salt exit. The drilling mechanical specific energy (MSE) was greatly reduced and the rate of penetration was significantly increased when compared to offset wells previously drilled in the area. This paper will identify, describe and discuss the factors leading to the creation of a smooth drilling environment, reduction in MSE, higher rate of penetration (ROP) and lower costs on this well. Introduction As the economics of drilling and completing wells in the deepwater Gulf of Mexico environment become more challenging, operators are seeking ways to maximize their reservoir recovery rates while minimizing non-productive time. This is even more critical with daily drilling spread costs in excess of $1 million dollars. To reach the reservoir with the optimally sized production casing, as well as to address other drilling problems including equivalent circulating density (ECD) limitations and swelling shales, more operators' drilling programs recognize a growing need for reliable concentric expandable devices. These reamers allow users to enlarge the hole below the last casing shoe so that tighter tolerance casing strings can be run. A key to reducing cost is being able to concurrently drill and expand the hole section in a single run. This paper describes the deployment of a newly introduced concentric underreamer coupled with a fit-for-purpose bit in the fourth of a series of exploration and appraisal wells in the Green Canyon area of the Gulf of Mexico with water depths over 4,000 feet. Drilling performance on this well is then compared to the previous two wells and clearly shows significant improvement in ROP, reduced MSE and lower vibration levels using this new concentric reamer and properly matched PDC pilot bit.

New sponge coring service and technology have been introduced to the oil and gas industry. Admittedly sponge coring has been an industry offering in some form for over twenty years but until now it has been plagued by chronic problems. The objective of sponge coring was to determine separate in-situ oil and water saturations of the formation materials. The problem with conventional coring has always been that the fluids would be expelled and lost from the core by the expanding gas while bringing it to the surface. The long-time solution was to surround the core with a special oil-absorptive (oleophilic) sponge material that would capture the expelled oil and hold it in place for laboratory analysis. The challenge was to fit the sponge tightly enough around the core to prevent fluid migration and mud contamination in the sponge-core clearance annulus, and yet avoid core jamming and sponge damage. This new, more accurate sponge liner coring service is now in place, showing excellent results. A balance seems to have been achieved between smooth core entry and a properly fitting, pre-saturated sponge with virtually no fluid migration. This new service cuts and provides oil-absorptive sponge-encased 3½-in. diameter core in 30 ft lengths with a maximum downhole temperature and pressure of 195°F (90° C) and 15,000 psi (1,034 bar) respectively. Special vacuum pump service equipment and sealing system are utilized to pre-saturate the sponge liner with brine. In late 2012 a major operator utilized this new and previously unproven system to core nearly 300 ft of sponge core in New Mexico, USA. The coring program used a special low-invasion coring fluid with a low spurt loss and a staged trip-out-of-the-hole schedule to minimize gas expansion/oil movement. The precision core bit that cut a tight-clearance core provided exceptional results with an average rate of penetration (ROP) of 10.4 ft/hr, with 97% core recovery and observable oil saturation in the sponge, indicating the system worked as designed. This case study will be described in detail within this paper.

In today's oil and gas industry, reducing drilling time and cost has become more and more important as wells have been drilled deeper and costs have risen. This paper will describe a case study of a well drilled in the Main Pass area of the Gulf of Mexico for a major operator. In this job, in order to eliminate a trip and significantly reduced costs, it was required to rotate a bottomhole assembly (BHA), including an expandable reamer, across a whipstock. This well contained several unusual challenges that will be described, including a shallow kick off and a subsequent extended-hole section to reach a proposed total depth (TD) in excess of 10,000 ft, drilling through sand and shale. The paper will describe the team process, coordination and communication required between the operator and service companies to make this unique job successful. Offsets will be compared with respect to drilling dysfunction, vibrations, time, costs, and the like. To reduce cost and non-productive time (NPT), it was decided to forgo drilling a long rathole out of the whipstock and proceed immediately with reaming on the next trip in. This approach required rotating the closed reamer across the whipstock, necessitating a series of analyses to limit the risk while performing this unusual feat. Extra trips were eliminated by using innovative well planning, procuring downhole tools with reputation of toughness and reliability, and finally requiring excellent cooperation between all involved parties. This job was confirmed to have saved the operator 29 hours of rig time and in excess of $250,000, while reducing the drilling plan by two days.