Drilling the lower overburden section in specific parts of the Greater Ekofisk Area (GEA) fields can be very troublesome. Wells in these parts may intersect shales with high gas content in the upper section (requiring high mud weight) and unstable zones with massive lost circulation risk (requiring low mud weight) near the base of the interval. These challenges have raised the need for a contingency drilling liner to "split" the section in two parts. Rather than changing the basic well design, the operator fronted the development of an 8-5/8″ expandable drilling liner with high collapse resistance for this purpose. This string provides 8.514″ post-expansion drift ID that accommodate an 8 ½″ bit size for the reservoir section, which is critical for GEA well design strategy. In the past five years, the operator has successfully installed 31 800 ft of 8-5/8″ expandable liner in 27 different wellbores with near perfect track record. The average liner length installed is 1 140 ft per wellbore, with an average installation time of 2.8 rig days. The solid expandable tubular (SET) drilling liner has been utilized both as part of the planned well design and as contingency liner. It has, on occasions, been worked down with parameters outside the stated specifications and still been successfully expanded afterwards. The 8-5/8″ expandable liner is now a proven system and has been one of the key enablers to achieve well objectives by maintaining hole size in a predictable manner. It provides a better drilling window for reservoir drilling and reservoir liner cementing compared to a conventional 7-3/4″ liner alternative. It also enables further contingency solutions in case other difficulties arise in the reservoir section. This technical paper describes how the operator in the overcame a significant geological challenge by working with an expandable pipe supplier to develop a unique size and strength of expandable liner that fits with the base case GEA well design. The paper also reviews the installation experiences, associated risks, performance, and key learnings with expandable liners.

Over the last few years, multiple wells have been drilled in the Norwegian Continental Shelf (NCS) and the United Kingdom Continental Shelf (UKCS) using wired drill pipe (WDP). This paper captures highlights from using real-time downhole measurements provided by WDP, for improved drilling operations. It presents learnings on how WDP measurements have been used in the operator's decision process. As part of WDP, along-string measurement subs (ASM) are equipped with temperature, annular/internal pressure, rotation and vibrations sensors. Data is transmitted to surface at high speed and is available in real-time, even when flow is off. The data provide great insight into the hole conditions along the drill string and at the bottom hole assembly (BHA). Based on this insight, drilling parameters at surface can be accurately adjusted, resulting in increased overall efficiency. Large data amounts can be communicated to and from surface with negligible time delay and independent from fluid circulation. Displaying the downhole measurements in real-time, both at the rig site and in remote operations centers has proven essential when optimising well construction activities. All parties need to access the same information in real-time. Moreover, the data need to be presented in an intuitive manner that enable improved operational decisions. To maximize WDP values, the Operator has learned that downhole data must be used to adjust drilling operations in real-time.

Continuous Circulation Systems (CCS) have been used in the past to help drill wells where interactions between the mud weight and theformation may increaserisks, thereby allowing the well to be drilledwithout encountering drilling problems or damaging the formation, whilst reaching total depth in the planned time. Previous systems have,however,relied on people working in the red zone. This paper discusses the process of making drill pipe connections, with continuous circulation,utilising a fully automatic deployment system to add value by removing the risk of people around the drill pipe during the connection, working in conjunction with other automated rig systems todeliver the advantages of continuously circulation over each connection. The continuous circulation subs are installed in every stand of drill pipe to be used in the drilled interval and facilitate circulation while the next stand is picked up and made up to the stump. A valve manifold is utilised to divert flow from the pumps to the subs, instead of the top drive, during the connection. During each connection, circulation is maintained down the drill string, from bit to surface, at drilling rates. Once the connection has been made the continuous circulation surface equipment is disconnected from the drill string allowing drilling to resume. After deploying the continuous circulation system on a number of geothermal projects, the results of using the system for top hole and intermediate sections suggest that while drilling with low rheology water-based mud systems,a high percentage of cuttings are returned to surface while the next stand of drill pipe is being picked up,limiting any hole loading and allowing the driller to increase the rate of penetration (ROP) through these sections. Fewer hole collapse issues were observed while drilling through volcanic tuff and ash, where wellbore stability is low due to poorly consolidated rock formations, thereby reducing non-productive time associated with stuck pipe and the costs of lost bottom hole assemblies (BHA's) and sidetracks. Most Geothermal projects work on very tight budgets and geothermal exploration costs need to be kept low. Improved drilling performance has improved the viability of these projects and increased the number of exploration wells that can be drilled in a campaign by reducing the days versus depth P90 estimate, that being the 90% probability of the rig matching the days v's depth curve predicted.

Advanced drill collar connections have been developed with 10 times extended fatigue life compared with the corresponding replaced connections. More than 4,000 advanced connections have been run in North America. Although these connections have demonstrated substantial fatigue strength improvement in operation, some failures have occurred. Multiple failed connection samples have been retrieved and analyzed for their failure modes and the root causes. In the failure analyses, manufacturing data were reviewed to identify any possible discrepancies between design specifications and manufactured components. The field run data were analyzed for the loading histories of the connections. The downhole fluid properties were also reviewed to identify their possible effects on the connection performances. The bottom hole assemblies were numerically analyzed to determine the loading distributions. The failed connection samples were physically processed and inspected in the metallurgical laboratory. Based on the combined numerical and testing analyses, the conclusions on the failure modes and the root causes were drawn. It was found that the primary failure mode for these connections was fatigue. The root causes for the fatigue failures can be divided into two categories: manufacturing causes and operational causes. Among the manufacturing failure causes, incorrect cold rolling is the primary one. The operation related failures were mainly caused by overloading. Through failure mode and root cause analyses, the manufacturing and operational related risks for the advanced drill collar connections were mitigated accordingly. It therefore greatly improved the quality assurance of the advanced connections.

For years the drilling industry has used sour service drill pipe within a narrow set of specifications and industry guidelines. That left room for original equipment manufacturers (OEM) to have customization on an iterative basis, which resulted in a wide product offering to fulfill operator needs. While this method worked, it did not lead to building the product in the most efficient and economical manner. As a result of this product diversity, drilling engineers could specify the best product to deliver their projects when running drilling models, only to have to redesign it around what is effectively available on rigs or for rental. This disconnect puts pressure on the industry players and is the result of a lack of standardization. We wiped the board to provide a simple solution that is more suited to allow alignment between operators, contractors, and rental companies. The new philosophy is based on the National Association of Corrosion Engineers (NACE) MR0175-2015 severity diagram, where environmental severity is defined in regions (1, 2, and 3), which have been used by oil companies’ engineers for their oil country tubular goods (OCTG) product selection. Even though the drill string will not be exposed to the well fluid for the same extended time and is surrounded by a more forgiving medium, the drilling fluid, the diagram allows a segmentation of customer's needs. This framework helped define targeted product properties. A research and development (R&D) and industrialization test campaign could then be started to confirm that sound product configurations could be offered with targeted properties. The study also explored the limitations imposed on connection make-up torque in a sour gas environment relative to the NACE severity diagram. Emphasis was given on methods to increase the make-up torque, which is needed to deliver the most extended reach wells that are now commonplace. The result of this two-year development campaign is a short list of grades with an optimized balance between pipe subcomponents strength and sulfide stress cracking (SSC) resistance. Region 1 (mild severity) products will offer as much tension and torque as possible, matching or exceeding these of API products, including excellent resistance to SSC, thus making drilling operation safer. Region 2 (medium severity) will offer products with medium to high strength and enhanced SSC resistance. Finally, region 3 (high severity) products will be aligned with the industry specifications for maximized SSC resistance and lower strength. This paper discusses a proactive approach that contrasts with a historical, more reactive one. As the drill stem technology leader, we saw an opportunity to drive this initiative that will benefit the drilling industry by offering a more natural way to select drill stem products. For the first time a sour service product range aligns with the needs of drilling engineers and the inventory of their selected service companies.

As the Managed Pressure Drilling (MPD) systems for deepwater drilling rigs mature, operators are applying the technology on more complex prospects. Wells are encountering higher pressures in deeper water depths, pushing against the boundaries of technical limits not previously encountered. A prospect in the US Gulf of Mexico required drilling to measured depths exceeding 31000 feet in water deepwater. Under such demanding depth, a non-typical drillstring was required to manage the tensile loading. Typical drill pipe connections on 6 5/8" S-135 tool joints are 8.5" diameter. This drill string would require V-150 landing string, with a 6 5/8" FH tool joint diameter of 8.875". Hard banding would bring the tool joint nominal OD above 9". The depth of the well and planned string RPM presented risk of casing wear, therefore drillpipe protectors would also be required. The depth of the reservoir and size of the drillstring meant pipe would need to be stripped out of the well with up to 900 psi backpressure in order to maintain constant bottom hole pressure. All well challenges were used to determine design specifications for a custom sealing element. The scope of work was to design, validate through finite element analysis, then validate in a test fixture per API16RCD test procedures. On conclusion of the product validation, a land test rig trial, with mock-up of the planned system, including dual sealing elements in the Rotating Control Device (RCD), the required non-rotating drill pipe protectors on the planned drillpipe, was executed. The development schedule from start to finish was compressed to less than 6 months also, targeting completion ahead of the rig's drilling program. This paper will recount the various phases of the design-build-validate-test effort that went into resolving these technical limits. It will conclude with field results and lessons learned from first deployment. As operators pursue more challenging deepwater wells, this systematic approach, through alignment of the operator, drilling contractor and MPD technology company, serves as a model to expand the operating envelope of drilling systems, improving safe performance in a cost-effective manner.

An Engineered Geothermal System (EGS) pilot project was commissioned to prove the economic viability of an industrial scale geothermal heat plant in Finland. The project aims to generate 40 MW of emission free heat energy, supplying up to 10% of the city of Espoo’s district heating needs. Two wells of 6400 m MD and 6213 m MD (measured depth) were drilled through formations of hard, abrasive granitic gneiss with maximum measured 560 MPa UCS (unconfined compressive strength). Typical dull conditions of lost and worn cutting structure and gauge diameter wear of between 3/16-in to ¼-in contributed to excessive torque, stuck incidences, low rate of penetration (ROP) and difficulties achieving build rate. To address these drilling challenges, this paper explores the interplay between new cemented carbide compact technology, drill bit design, and drilling parameter road mapping. The directional section of the first well was drilled with an average ROP below 2 m/hr and run length averaging 56 m per bit. The well took 246 drilling days and 44 BHAs (bottom hole assemblies) to achieve TD (total depth). Between the first and second well an application specific drill bit design package and step-wise parameter program were implemented. Design enhancements included improved gauge protection, bit hydraulics for minimizing cone erosion and subsequent TCI (tungsten carbide insert) compact loss. Novel hybrid TCI materials technology was introduced having a 100% improvement in wear resistance and durability as compared with conventional grades, to drill these hard and abrasive granitic formations. New BHAs and drilling plan were selected based on the bit design selection to reduce wear on BHA components, improve directional control and reducing drilling dysfunctions. Once these factors were under control, a low risk approach to extending the bit revolution limits (krev) for the roller cone sealed bearings could be implemented based on downhole parameters and previous bit dulls, leading to longer run lengths. The combination of bit design and material enhancements with a properly selected BHA and drill plan increased run lengths and ROP. The second well’s 8.5-in directional section was drilled with a 13% increase in average ROP and a 69% increase in average run length without exceeding krev limits. Well on well, a 77 day reduction in AFE (authorization for expenditure) was realized. We demonstrated the combination of oil and gas bit and BHA design, drilling plan, and new cutting material capabilities can reduce EGS well construction costs in order to make these renewable energy sources economical.

Drilling specialty tools and accessories are often machined with large Inside Diameters (IDs) so that the necessary electronic packages can fit within the component. As the ID of the component increases, the wall thickness of the pin connection is reduced. It has been established that the machining of a Stress Relief Groove (SRG) on the pin connection with a standard-sized ID will greatly improve the fatigue performance of that connection. However, no such consensus has been reached regarding the machining of SRGs on the pin connections of these special-purpose tools with large IDs. The common concern is that the wall thickness of the pin connection has been reduced so much by the large ID that the machining of a SRG would drastically deteriorate the performance of the connection. This paper addresses that concern by providing in-depth analysis of various API connection sizes tested over a broad range of IDs. Finite Element Analysis (FEA) was used to quantify the difference in fatigue life between connections with stress relief features versus without stress relief features. Additionally, calculations were performed to understand the reduction in the capacity of the connection that results due to machining stress relief features. This paper gives the comparative fatigue life for each of the connections modeled where the API recommended Make-Up Torque (MUT) is adjusted to compensate for the increasing ID of the connection. In every case, the benefits of machining SRGs on large ID connections are significant. Allowing larger IDs in connections where SRGs are required will bring the technical benefit of allowing larger electronics packages to fit within the bore and increased hydraulic performance, among other benefits. Additionally, the drawbacks to SRGs are considered and quantified whenever possible. Possible solutions to these drawbacks are proposed as a way to lessen their effects so the full benefit of cutting the SRGs can be realized. In total, by looking at the potential gain in fatigue life against the trade off in lost capacity, this paper provides operators with the ability to determine the suitability of stress relief features on their components with large IDs. For those connections where a SRG is required, this paper provides guidance as to the connection's performance at various large IDs.

Bending Strength Ratio (BSR) is a time-honored technique for choosing BHA connections, and is often the basis for the popularity of some connections over others. However, experience and some isolated research indicates that it might not be accurate in predicting the best connection. This paper attempts to use Finite Element Analysis (FEA) coupled with fatigue-life modeling to develop a systematic picture of the effectiveness of BSR as a design criteria. The modeling process used has been developed previously ( Ellis et al 2008 , for example). Each connection and collar size studied is modeled in detail using Finite Element Analysis (FEA) techniques, and the resulting stresses and strains can be used to calculate the number of cycles to failure for a given set of parameters. These results are not accurate for predicting actual component failure, but they are helpful for comparison between options to choose the best designs. This work represents a fairly-complete cross section of the BHA connections in regular use, studied for their relative performance. A challenge of directly modeling fatigue lives is finding a way to compare the results for global patterns. Since different collar sizes will have different applied stress levels at different curvatures, a method for normalizing the results is developed here. This allows an easy global comparison between the different connections. The outcome of this in-depth study of connection fatigue-modeling results is a surprise: BSR is not helpful for design, and there seems to be no clear pattern for ID and OD sizing. Instead, the drill string designer should choose the right connections at the time of manufacturing, and use a normalized comparison method to determine the relative risk in each operation.

During drilling operations, high drillstring vibrations may originate from various sources, namely, the bit-rock interaction, drillstring-wellbore contacts, stick-slip phenomena, fluid-structure interaction, and mass unbalances. Excessive vibrations may induce drilling equipment failures (fatigue, cracking, washouts, and ruptures), which can be costly and catastrophic. Therefore, it is crucial to accurately model the drillstring dynamics in order to help drilling engineers make better decisions and avoid harmful vibrational effects. This paper proposes a numerical model developed in the time domain to estimate the drillstring lateral, axial, and torsional dynamics. It is based on the finite element method coupled with the Craig-Bampton reduction method ( Craig and Bampton 1968 ) to reduce computation time. The drillstring-wellbore contact forces are automatically determined and may occur on both tool-joints and drill pipe bodies, and the drilling fluid is accounted for by its inertial and frictional effects. The efficiency, accuracy, and predictive capacities of the model are assessed by comparing the computational results to downhole measurements for a case study of a non-conventional well. A good agreement for both lateral and torsional vibrations is obtained. The numerical results are used for a more detailed analysis on the lateral and torsional vibrations of the system. The evolution of lateral acceleration, from a forward to backward whirling tendency on the system, can then be assessed with the use of a spectral analysis. The novelty of this dynamics model is that it can portray a realistic geometry of a drilling assembly in 3D curved wells with the fluid presence and gives a complete study of the coupling phenomena between the axial, torsional, and lateral vibrations. The use of this novel dynamics model along with downhole data acquisition and wired pipe technology is one of the essential steps towards drilling automation to provide a better mitigation of drillstring vibrations.

In different inspection standards, corrosion pits in drill pipe tubes are treated in different ways. Sometimes they are considered a stress concentrator and subjected to relative depth limitations (like a maximum of 10% of the adjacent wall); sometimes they are only considered as a location of wall loss, so the steel thickness underneath them is the only acceptance parameter. This work clarifies the difference in severity between these two types of imperfections, and enables the definition of a reasonable inspection process. Slip cuts and corrosion pits with varying depths were modeled using Finite Element Analysis (FEA) techniques for multiple drill pipe sizes. The resulting stresses and strains under tension and bending loads were used to calculate the fatigue lives of these components. The resulting number of cycles to failure does not correspond to the real lifetime of real pipe—there are too many variables and neglected parameters—but the results can be compared within the data set to determine which options are better and worse and by how much. Significantly, this research validates the approach taken by some standards to neglect the stress concentration effects of corrosion pitting, only considering the wall thickness remaining for the purposes of inspection. The commercial benefit to this is huge: it allows the inspector to not have to reject or repair a drill string’s worth of light corrosion pitting. This research indicates this is valid and safe in many cases, but in the more-stringent inspections used for offshore drill pipe the relative depth of the pitting also needs to be considered.

This paper documents the development, qualification and field test deployment of an electrically powered and wired drill pipe system for use by operators, drillers and service companies in oil & gas drilling operations. Deployment of the technology has the potential for users to power downhole tools from surface and thus reduce or remove downhole batteries / turbines. High-speed bi-directional telemetry over the wired drill pipe can improve realtime communications and downhole measurement quality, while enabling high frequency, surface and downhole data sharing / integration. The development of the system is centered around: a braided conductor and an insulating material a robust field replaceable pipe connector system transceivers optimized for the transmission characteristics of the system The novelty of the new drill pipe design is the ability to supply downhole tools with power in addition to bi-directional high-speed data communication telemetry from surface over the same braided and insulated conductor, manufactured into the ID profile of the drillstring. Due to power regulation at surface and matched transceivers, the need for in-string communications repeaters is avoided. In addition, special attention has been paid to the design, robustness and field maintainability of the connector system at each end of the drill pipe. Qualification of the system in a laboratory environment applied downhole drilling conditions using simulators, highly accelerated life tests ("HALT"), and physical testing on discrete samples, joints and short strings of drill pipe. Transceiver performance, connector make/break cycles and testing of the conductor and insulating layer under tension, bending, torque, pressure, temperature and erosion were all performed. Parallel "real life" runs on testing and commercial drilling rig operations have yielded encouraging early results to validate the qualification laboratory testing. Minimal damage was observed during handling and downhole use on several drilling rigs, indicating that the system has the potential to be handled as regular drillpipe and can be simply integrated into rig operations. Several iterations in design and testing of the braid and insulating material have proven the viability of new manufacturing techniques and given valuable insight as to the ability of the design to withstand normal drilling conditions of flow, torque, tension, pressure, temperature etc. gained through commercial drilling rig testing. System trials on rig operations have shown that stable downhole power can be delivered whilst communicating with a minimum bit rate of 56Kbit/sec during drilling. A top drive slip-ring assembly at surface and a crossover to a service company BHA downhole have been developed and were used for the drilling trials.

Stick-slip is a torsional vibration mode observed in drilling systems, which are used in creating boreholes for the exploration and production of oil and natural gas. This paper presents a method to create and assess stick-slip in the laboratory environment. This is achieved by using the hardware-in-the-loop method, where a numerical drillstring model is combined with an experimental drilling machine. In this setup, the numerical model captures the axial and torsional oscillations between the surface and the drill bit, while the drilling machine acts as the hardware in the loop, capturing the actual bit-rock interaction. The proposed framework allows creating self-excited stick-slip oscillations in a controlled, repeatable and measurable manner. This enables reducing the risk, cost, and time for activities related to testing, developing, debugging or optimizing any stick-slip related tool or mitigation concept.

This paper describes how one Permian operator used analytics and torque and drag modeling in real time to gain situational awareness of ongoing poor weight transfer during slide drilling in a lateral. Much-higher-than-planned dogleg severity caused severe helical buckling that decreased rate of penetration and ultimately resulted in damaged drillpipe in the buckled region. Because of the model's predictions of drillstring abuse, the operator ordered a post-well inspection earlier than usual that helped prevent drillstring failure on subsequent wells. Finally, insights gained through real-time analytics helped consider options to mitigate poor weight transfer on future wells. Positive Displacement Motors (PDM) offer economic efficiencies for unconventional operators, but there are limitations with weight transfer to the drill bit, especially in extended laterals. The requirement to slide during directional trajectory changes may induce premature drillstring failure by causing severe buckling and stress. Directional control in the subject well deviated significantly from the plan which was believed to be a major contributor to the poor weight transfer to the bit, known as weight stacking. With the use of real-time engineering models and analytics apps, the operator was able to monitor the loads placed throughout the drillstring. Buckling analysis predicted when the drillstring entered either sinusoidal or helical buckling. Broomstick plots for hookload and surface torque provided information on friction factors and the health of the wellbore. von Mises stress was monitored to compare the combined stress load to drillpipe yield strength along with other component stresses including axial, bending, torsional, and various shear stresses. These applications integrated with real-time monitoring identified long periods while sliding in the latter half of the lateral where erroneously high weight on bit (WOB) at the surface indicated weight stacking on the drillpipe. They also revealed extensive buckling that caused poor weight transfer to the bit, which reduced rate of penetration (ROP) and increased drilling time. It is important to note that the entire drillstring had been inspected (DS-1 Cat-4) prior to drilling the subject well and, therefore, would normally not have been inspected again after the subject well. The operator chose to re-inspect 21 joints that were exposed to the most severe buckling while drilling the lateral, specifically when stacking weight on the drillstring in an attempt to increase PDM differential pressure and ROP during slide drilling. Results showed 71% of joints were damaged and required repair. Of the damaged joints, 20% were so severely damaged that rigsite repair was not possible. This paper shows how the use of real-time analytics can help monitor drillstring buckling and stresses and detect harmful patterns such as stacking weight to improve real-time decisions to mitigate damage. This information can also help plan subsequent wells and drillstring designs.

Lateral vibration modeling of certain BHA (bottomhole assembly) designs has shown great sensitivity to the proximity of stabilizer blades. In a previous paper, the BHA chatter vibration mode was presented, including the basic theory and three field examples. In each case, lower drilling rates were associated with higher levels of BHA dynamic dysfunction as determined using a lateral vibration model. One case clearly illustrated a reduction in effective weight applied to the bit, determined using bit dull grade results. This paper will further explore the mechanisms in which BHA dynamic contact forces can act to reduce the effective weight on bit. The contact forces that push a stabilizer blade to be constrained within a borehole include both static and dynamic components. The dynamic forces are difficult to visualize as they are generated by the BHA in motion, and a well-formulated dynamic model is required to evaluate these forces. In drilling, we simply see the effects as worn and damaged drillstring components. A frequency-domain BHA lateral vibration model represents lateral vibration flexural waves propagating in the BHA. This model can be used to calculate dynamic side forces acting at stabilizer and LWD tool blade contacts with the borehole for reference excitation forces. These contact forces may be strong functions of rotary speed and BHA contact spacing, and they typically create a non-trivial level of residual drag that impedes getting weight to bit. The physics of dynamic contact forces are similar in some respects to static contact forces. Superposition of the dynamic modes illustrate that, although an individual component may vanish momentarily, additional modes and phases can constructively combine such that the total force summation does not vanish. The net result is that dynamic forces can generate significant lateral forces that are similar to static contact forces. Static effects are known to impede application of weight to bit in deviated and horizontal wells, and small ledges can prevent a stabilizer blade from moving forward. Dynamic effects from improper stabilizer placement are potent sources of lateral dysfunction that can have a similar effect. BHA dynamics have the potential to both create borehole irregularities and resist forward motion resulting from contact forces between drilling tools and the borehole.

Surface-based damping mechanisms are the most commonly used method to mitigate stick-slip vibration in drilling systems, and their parameters are typically chosen based on low-order models of the drilling system. Field experience indicates that these low-order models do not capture all deformation mechanisms, and there is a need to include higher-order modes of deformation in the model. As a result, it is also imperative to delineate the effect of the surface damping mechanism on the higher-order modes of deformation, and vice versa. This work investigates this interplay using a combination of analytical methods, numerical simulations, and field data analysis. The effect of surface-based damping mechanisms, in principle, is similar to that of vibration absorbers used to quench self-excited oscillations in nonlinear systems. Therefore, to determine the stability of the drilling system as a function of the surface damper parameters, a torsional model of the drillstring with a negative damping boundary condition at the bit is considered. For this system, the stability chart determining the rate of growth of amplitude of the natural modes as a function of the surface damper parameters is shown to depend on the operational parameters and on the configuration of the drillstring. These analytical observations are then evaluated using transient numerical simulations of a coupled axial-torsional model of the drillstring, with a realistic bit-rock interaction law. Finally, the efficacy of the analytical and numerical model in reproducing field results is demonstrated by analyzing downhole rotational speeds of the bit acquired using high-frequency data acquisition sensors. The results described in this paper provide a mechanism to determine the effect of the surface damper parameters on the higher-order dynamics of the drilling systems, and provide a rationale to determine consistent damping parameters that do not adversely affect the higher-order dynamics of drilling systems.

The drilling industry has become enamored with the extra torsional capacity and clearance that are available when double-shouldered connections are used in the place of the single-shouldered connections that are in the public domain. These proprietary connections allow us to drill farther, faster, and with less damage to our drill string. To this point, however, no analytical model has been introduced that can accurately calculate the tensile and torsional capacities of these useful connections. Typically, the connection designer and/or manufacturer creates an empirical formula that is calibrated through laboratory and field testing. This approach is perfectly acceptable, but it hinders those tool designers that need something different from what is offered on the public market. It is rarely cost-efficient to perform laboratory and field testing for a one-off connection design. Single-shouldered connections, such as API drill stem connections, have a straightforward analytical equation that can be used to determine the capacities of any connection. This equation may not be perfect—it relies on linear assumptions that are probably not descriptive of the connection loading—but several decades of use have allowed the industry to be confident in its strengths and aware of its shortcomings. Thus, what is needed is to simply extend the approach of the original single-shouldered equation to account for a second shoulder. Though the mathematical complexity increases a bit, the assumptions are the same, lending the same confidence to the extended equation that the industry has for the original. This paper presents the derivation of just such an equation. The implicit assumptions present in the original equations are discussed, and then the same ideas are applied to a double-shouldered connection. The full set of new equations are developed and described, including tips on their practical use gained from tool-design experience.

To date, extended reach drilling (ERD) wells drilled on one of the main UAE offshore reservoirs have been delivered by using a tapered drill string design that combines two sizes of drill pipe. To reduce the number of days per well, a one-size only drill string concept has been considered, but such an option required some improvements in torque and geometry to meet specific well design requirements. An initial analysis of the drilling requirements in terms of torque, dimensions, tensile capacity, and hydraulics showed that the process limiter was the drill pipe connection as no option was available in the market that could meet the redesigned requirements. Two new technical solutions were separately developed that took into account the need for a reduced tool joint outer diameter (OD) for equivalent circulating density (ECD) and fishability in an 8½-in. hole. Once developed, the solutions were then validated for manufacturing and field trials. The first solution consisted of designing and developing an ultra-high torque thread profile, while the second solution suggested to upgrade the tool joint material grade of a new 4th generation double shouldered connection. Both newly designed drill pipe strings successfully passed the shop stress tests and were mobilized for operations. The drill pipes were used for drilling within the tight hydraulic window of such ERD wells, further validating the original drilling simulation parameters. The successful trial of these two single size string solutions enabled the saving of more than five days of rig operating time per well. This paper presents a detailed comparative evaluation of two innovative drill pipe design solutions that enable operators to run a single size string in challenging ERD wells. It also provides an insight into the operational benefits obtained by shifting to the new single size string.

A drill string in a wellbore always contacts a casing. However, in a curved section of casing the contact force between the drill string and the casing can be significant. Friction between the casing and a rotating drill string tool joint in contact with the casing generates a heat source at the interface between the two objects. The generated heat energy is a function of rotational speed of the drill string, side force and friction coefficient between the hard-banding layer covering the tool joint and the casing. Heat partition between hard banding layer and casing depends on the thermal properties of both. When there is no mud circulation, e.g. due to a pack-off in the annulus or lost circulation, and the contact region stays in the same section, the resulting temperature increase can lead to degradation of the mechanical strength of both the drill string tool joint and the casing. In addition, the casing strength reduction can facilitate casing wear, which may lead to leak and tool joint heating can lead to heat checking cracks or mechanical strength weakening which may result in a parted drill string due to brittle or ductile fracture. When there is no mud circulation, rotation of the drill string leads to mud angular rotation inside and outside the drill string. Convection heat transfer occurs due to mud rotation and convection heat transfer coefficient depends on mud flow regime. CFD simulations were performed to compute the convection heat transfer coefficient. Two and three-dimensional steady state and transient finite element simulations were performed to compute the temperature distribution in the casing and the drill string tool joint when there is no mud circulation. Results show that, when there is no mud circulation, conduction through the drill string and casing has the highest impact on the maximum temperature generated due to frictional heating. Two graphs are plotted, one shows the steady state temperature versus side load at different rotational speeds while the other shows casing yield and ultimate stresses degradation versus increase in temperature. Both graphs can be used by drilling engineers at the well design phase to select the appropriate rotational speed of drill string to avoid failure when there is no mud circulation. Novelty of this paper is in thermal analysis of a tool joint hard banding layer rubbing against casing. In the analysis the convection heat transfer through mud rotation is involved.

Heavy vibrations in the bottom hole assembly (BHA) may cause permanent damage to the bit or other BHA components, like measurement while drilling (MWD) tools or rotary steerable systems (RSS). Tool- joints along the drill-string may get warned out by high levels of whirl along the drill-string. Repetitive shocks of drill-pipes against the formation may be the origin of wellbore instabilities or cause malfunctions of the communication network of wired drill-pipe high speed telemetry communication systems. Because of all these potential problems, it is important to better understand how pipes move inside a wellbore. High frequency recordings of triaxial accelerometer measurements at different locations inside the BHA, or along the drill-string, open the possibility to reconstruct the actual displacement of drill-string tubulars. However, because accelerometer readings are taken in a reference frame that is not in uniform movement compared to a fixed referential, the readings are subject to complex effects of centrifugal, Coriolis and Euler accelerations that make the estimation of the pipe movement rather intricate. Without considering these so-called fictitious accelerations, it is easy to misinterpret the actual movement of the accelerometers attached to a pipe. For that reason, a numerical method has been developed to calculate the displacement of the support of the accelerometers. To validate the numerical model, a laboratory setup has been built that allows for a precise control of the movement of an element that supports three triaxial accelerometers. The known displacements of the accelerometer support and the reconstructed displacements have been compared and a methodology has been developed to use the redundant measurements to reduce the uncertainty of the estimated movement resulting from inaccuracies around the exact position and orientation of the accelerometers relatively to its support. Lately, several publications have reported results from high frequency triaxial measurements at different locations along the BHA and the drill-string, while others have pointed out the risk of misinterpretation associated with the existence of fictitious accelerations. This paper presents a validated numerical method that allows for an accurate reconstruction of the displacement of drill-string and BHA elements therefore providing a unified point of view to the problem of estimating drill-pipe displacements based on accelerometer measurements.