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Collaborating Authors
North America
Abstract This paper focuses on anti-collision best practices developed and implemented by Liberty Resources for horizontal drilling across pre-existing horizontal wellbores within the same horizon in the Williston Basin. These multidisciplinary collaborative workflows have allowed Liberty Resources to successfully drill multiple complex horizontal wellbores traversing as close as 10 feet wellbore-to-wellbore to existing laterals. As the horizontal infill development of unconventional reservoirs progresses, complex wellbore trajectories with heightened collision concerns will be required. To achieve this requires advancing the industry's anti-collision standard practices with new and more precise anti-collision methods, detailed planning, and near perfect execution. In the Williston Basin alone there are over 13,000 vertical wells, 15,000 horizontal wells, and over 1,000 re-entry and directional wells drilled to date, with the first horizontal wells introduced to the basin over 30 years ago. Historically, the horizontal wells were drilled using a vast array of well designs and orientations due to the limitations of technology, industry practices and standards, and the insufficient understanding of the reservoir. Advancements in drilling and completions technologies and a better understanding of the reservoir now allow leases to be reassessed for infill potential. This increased infill development has led to increasingly complex wellbore trajectories with collision concerns not only for existing vertical wellbores but now also for existing horizontal wellbores within the same or proximal horizons. The anti-collision best practices include directional and geologic planning considerations, operational tolerances and requirements including zonal determination, communication protocols, and risk management practices. Creating a broad framework that allows for flexibility to adjust for distinct operational constraints. These workflows and tolerances have been implemented in three horizontal wellbores traversing seven same-formation pre-existing horizontal wellbores. The anti-collision method was successfully applied in both the Middle Bakken and Three Forks formations, each with their own varied and unique geologic characteristics, demonstrating applicability for a wide range of reservoirs. The ability to execute complex wellbores opens new opportunities to access additional resources in previously considered "fully developed" acreage. The methods presented in this paper have allowed the routine drilling of horizontal laterals as close as 10 feet to existing laterals. This technology can be applied to a variety of reservoirs opening new opportunities to access additional resources previously considered unrecoverable due to existing wellbores.
- North America > United States > North Dakota (1.00)
- North America > Canada (1.00)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > Montana > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin > Three Forks Group Formation (0.94)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.94)
Drilling in the Delaware Basin with Shaped Diamond Elements Reduces Vibration and Increases Reaching Target Depth
Phillips, Anthony (Baker Hughes a GE Company) | Rickabaugh, Caleb (Baker Hughes a GE Company) | Gray, Joel (Baker Hughes a GE Company) | Savage, Michael (Baker Hughes a GE Company) | Ramsey, Josh (Baker Hughes a GE Company)
Abstract Lateral stability at low depth-of-cut (DOC) has been a key factor affecting the durability and performance of polycrystalline diamond compact (PDC) bits. This paper describes how Shaped Diamond Element (SDE) technology proven in the laboratory and in Delaware Basin well construction can increase stability and boost performance with 66% improved footage while drilling 40% faster. The technology enables modifications to the cutting structure that changes the PDC bit stability response, controlling lateral instabilities. Full bit laboratory testing was used to measure a PDC bit's lateral stability during drilling. . An experimental, intentionally unstable 8.75-in. 6 blade PDC bit frame was designed as a baseline for testing, and a second bit with the same basic frame was built incorporating the SDE technology. Tests were run to examine the effect of exposure and number of shaped diamond elements on the bit's stability. The bits were tested at atmospheric pressure, in different rocks to indicate their response in soft and hard formations. The learnings from these tests were then applied to an 8.75-in. 7 bladed PDC bit for use in the Delaware basin. The SDE field test bits were equipped with in-bit sensing to confirm the benefits in operation that were observed in the laboratory test. Data from their runs are compared with offsets to quantify the benefit of the SDE technology over a number of months During laboratory tests in a soft limestone an instability boundary line was determined at 28% lateral instability, with a higher value indicating a more unstable bit. The baseline bit started at 28% indicating instability at low depths of cut and reached 100% with increasing DOC. The SDE bit designed for early engagement remained stable through the entire test independent of depth of cut achieving a 6% instability level. To establish the design criteria to maximize the stability benefits, the bits were tested with varying number of strategically placed SDE, and varying DOC. During the field runs with this technology, the results indicated an improvement in dull conditions increasing target depth (TD) rate by 21% and increasing the distance drilled by 10%. In one particular case, comparisons of the vibration data from the in-bit sensor showed a 42% reduction in drilling dysfunctions for this given interval, on consecutive wells on the same pad. The reduction in vibration reduced cutting structure damage yielding an increase in rate of penetration (ROP) by 40% and footage by 66% over offsets. Recognizing these dysfunctions associated with lateral instability as the most damaging to the bottom-hole assembly (BHA) it is important that they are mitigated or controlled. The drilling costs and efficiencies today are significantly important; they are the key to reduce any non-productive time (NPT). As the field data demonstrates, SDE that engage and cut the rock, can provide stability benefits that improve the bit's durability without reducing the bit's performance.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.92)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Mountain Group Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
Abstract Occurrence of reversible mud losses and gains while drilling in naturally fractured formations is of primary concern. Borehole breathing can greatly complicate the already difficult practice of fingerprinting the changes in the return flow profile, hence undermining the reliability of kick detection. Issues can also derive from misdiagnosing a kick and attempting to kill a breathing well. The objective of this work is to correctly address the phenomenon and increase insights of its physical characterization. The fluid progressively flows in and out of fractures as a consequence of three mechanisms: (1) bulk volume deformation, (2) fluid compressibility, and (3) fracture aperture variation. To represent this complex scenario, a model involving a continuously distributed fracture network is developed. A time-dependent, one-dimensional dual-poroelastic approach is coupled with a variable fracture aperture and a passive porous phase. Finite fracture length is considered and no limitation on the number of fractures is posed. The latter permits us to analyze long open-hole sections intersecting several fissures, which is a more realistic approach than the available single fracture models. The proposed model is able to quantify pressure distribution in fractures and pores, together with the flow rate entering or exiting the fractures. When the fissured space is reduced to zero and incompressible bulk volume is considered, the solution reduces to that of classical reservoir engineering. A sensitivity analysis is performed on the physical properties of the formation and the drilling fluid. The latter provides a deeper insight on the factors that significantly influence breathing phenomena (i.e. drilling fluid weight, rheology and formation mechanical properties). Furthermore, a very useful application of the model is proposed by suggesting its application as a breathing discriminator during kick diagnosis. The shut-in drill pipe pressure, recorded from a real kick, has been compared to one caused by a simulated breathing case. Although the two SIDPPs show great similarities, the correct modelling of breathing can significantly help the identification of the major differences between a kick and breathing. Altogether, a comprehensive in-depth characterization of borehole breathing can help with kick diagnosis and can be used to effectively design unconventional drilling techniques such as Managed Pressure Drilling.
- North America > United States > Texas (0.93)
- Asia > Middle East (0.68)
- Europe > Norway (0.66)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.97)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.97)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.97)
Abstract Various generations of double-shouldered drill pipe connections have been developed in the past 30 to 40 years with performance as a primary driver. The objective was to bring improvements in torque and hydraulics to satisfy drillers' needs. The record extended reach drilling (ERD) wells could not have been delivered without these technological advancements. The driver for these developments was solely on improved performances, with limited focus on cost, as these technologies were so enabling that the associated costs were deemed acceptable. When these same connections started to be used on land rigs to deliver wells in a factory drilling fashion, where cost control is of higher importance, the cost of maintaining these premium connections started to become more apparent. It, therefore, became obvious that a different approach was needed to meet the combined need for performance, as well as a lower cost of ownership post acquisition. A comprehensive two-year research and development (R&D) program was carried out to evaluate various design options. After the research was conducted, a design was chosen that allows better control of stress inside the connection. This allows users to benefit from other design features besides the torque and hydraulics of a streamlined connection. The R&D program included numeric simulation and mechanical lab testing. More specific elements of the design allowed more tolerance related to field damage of the connection, less material loss on repairs, and more importantly, a ruggedness so that the connection can remain in the field longer rather than needing to be repaired so often. The final stage of qualification was a field trial at the manufacturer's test rig facility. A post field trial inspection confirmed the improved serviceability and ruggedness, qualifying the connection for commercial release. The 4 generation double-shouldered connection was first put to task in the Permian basin. A rental string was dispatched to a land rig and used to drill the longest and fastest lateral in the area. The tapered 5½ in. by 5 in. drill pipe string, which comes with tool joints of a similar size (this of 5 in. drill pipe), drilled the well and saved two days off the estimated drilling plan. Subsequently, more strings have been deployed, and more data shall be gathered in this paper to demonstrate the low repair rate. A new approach has been used to design a connection that performs at high torque levels but also demonstrates improved serviceability and a ruggedness approaching that of an API rotary shoulder connection.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Equipment (1.00)
Abstract A significant challenge associated with cementing across salt zones in the Williston basin is mitigating risks of casing collapse or deformation. An operator (Operator A) in this area reported that six of their old wells experienced casing failures/deformation caused by salt creep. Post-job analysis showed that these older wells used conventional cement designs. Based on the lessons learned from successful cement jobs for other operators in the same region and knowledge about salt creep loads, tailored fluid systems were proposed with optimized job design and placement procedures for Operator A's upcoming wells. This study demonstrates the benefits of the proposed modifications by comparing the logs and outcomes of old and new wells. Through post-job analysis, this study highlights the importance of using cementing simulation and modeling software to design a dependable barrier. The casing inspection logs and cement bond logs across salts from old wells indicated that deformation occurred within a few weeks of cementing. The use of a tailored cement system with enhanced mechanical properties, along with specialized spacer systems and effective centralization, showed improvement in bond logs, no casing deformation, and better casing-cement bonding in the new wells for Operator A. Pre-job simulations were performed using in-house cementing software to verify the cement job and to help ensure that the cement was effectively placed in the annulus. Cement sheath integrity modeling software was used to simulate the actual exerted loads from plastic salt formations and subsequent drilling, completion, and production operations. This software uses a semi-empirical creep law that describes the creep process of a wide variety of salts. The cement system with enhanced mechanical properties showed sufficient endurance to provide a dependable barrier to the salt creep loads experienced in Williston basin wells. Although the use of salt vs. salt-free slurries is debated for salt zone cementing, this study shows that salt-free cements with enhanced mechanical properties can be used successfully when there is no risk of cement gelation during placement. North Dakota salts principally contain halite (NaCl), which does not pose a risk of gelation. The case histories and field studies discussed establish cement systems and practices that can help to minimize the risk of casing deformation and improve the cement bond across salt zones in the Williston basin in North Dakota. This tailoring tool, with its unique ability to exert salt creep loads, helps to minimize the risk of cement sheath failure through tailored barrier designs. This information should help the petroleum industry to address long-term well integrity problems associated with cementing across plastic salts.
- North America > United States > North Dakota (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Halide > Halite (0.56)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- North America > United States > Montana > Williston Basin (0.99)
Optimizing the Deepwater Completion Process: Case History of the Tamar 8 Completion Design, Execution and Initial Performance - Offshore Israel
Healy, John (Noble Energy) | Waggoner, Steven M. (Noble Energy) | Magin, Ian (Noble Energy) | Beavers, Matt (Noble Energy) | Williams, Kevin (Noble Energy) | Hebert, Russell (Noble Energy)
Abstract A case history from Offshore Israel is presented that describes the successful delivery of one (1) ultra-high rate gas well (+250 MMscf/D) completed in a significant (11.5 TCF) gas field with 7 in. production tubing and an Open Hole Gravel Pack (OHGP). The well described, Tamar 8, was completed approximately 4 years after the start of initial production from the Tamar development. Several operational innovations and process improvements were implemented that resulted in a significant reduction in rig time. A novel multi-purpose integrated tool string design enabled the sequential drilling of the pilot hole, underreaming of the reservoir section, several fluid displacements and casing cleaning in a single trip. The completions were installed with minimal operational issues (completion Non-Productive Time, NPT = 2.6%). Production commenced in April 2017. The initial completion productivity of this new well exceeded the five wells completed in 2012. Peak production rate to date is 281 MMscf/D.
- Europe (1.00)
- North America > United States > Texas (0.69)
- Asia > Middle East > Israel > Mediterranean Sea (0.29)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.94)
- Geology > Mineral (0.68)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > South East Galeota Block > Cannonball Field (0.99)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Mari-B Field > Yafo Formation (0.99)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Mari-B Field > Noa Formation (0.99)
- (5 more...)
Abstract Throughout the years, evolving industry practices have inspired new technology, and novel technology developments have led to new industry practices. This cycle continues, particularly since the industry has evolved to horizontal unconventional wells as one of its primary development mainstays. While unconventional fields progress beyond the early stages of development, the original wells in the field become candidates for mature asset considerations of how to economically extend the life of the aging wells. Completion design evolution in each of the major shale plays suggests that the early-time stimulations were inadequate for optimum recovery. Long laterals with reservoir exposure spanning across thousands of feet and having hundreds of perforation holes make precision during conventional restimulation methods complicated and/or costly, often with unpredictable production results. Advancements in cement slurries and wellbore construction practices have enabled the development of a refracturing methodology that allows for complete renewal of stage isolation along the wellbore. Through installation of a smaller casing string inside a legacy well's existing production casing and effective cement isolation in the annulus, an existing wellbore can be transformed into a new closed system that can be subjected to a new completion design providing increased and accelerated reserves. Specialized casing sizes might be necessary and the refracturing completion might be rate-limited in comparison to a new drill completion, but the process has confirmed execution repeatability and less variance in production predictability than other refracturing techniques. The successful implementation and economic return of this casing-in-casing refracturing method has caused a growth in popularity of this style of refracturing, both in total well count and in quantity of participating operators. In the Burleson County Eagle Ford formation, multiple recompletions using this technique have been performed. Of the six casing-in-casing refractures performed, five had sufficient production time to derive an average estimated ultimate recovery (EUR) increase of approximately 140% in comparison to the original well EUR in the detailed Eagle Ford acreage.
- North America > United States > Texas > Burleson County (0.60)
- North America > United States > Colorado > Eagle County (0.60)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (3 more...)
Footage in STACK Lateral of Oklahoma Increased by 185% through New Non-Planar PDC Cutter Geometry Development and Implementation
Lyons, N.. (Baker Hughes, a GE company) | Izbinski, K.. (Baker Hughes, a GE company) | Pauli, A.. (Baker Hughes, a GE company) | Gavia, D.. (Baker Hughes, a GE company) | Hoffman, M.. (Baker Hughes, a GE company) | Cantrell, B.. (Baker Hughes, a GE company) | Bryant, S.. (Baker Hughes, a GE company)
Abstract The development of improved synthesis techniques for polycrystalline diamond compacts (PDC) positively impacted fixed cutter drill bit performance. Coupled with these advances, recent developments in cutter geometry show improved cutter performance in many applications. Laboratory and field testing has demonstrated that modifying the face geometry of the PDC cutter used in a fixed cutter bit is one of the most direct ways to affect the efficiency and longevity of the bit's cutting structure. This paper describes a new non-planar cutter face geometry that has increased footage drilled, rate of penetration (ROP), and improved the bit dull condition in the Meramec formation in western Oklahoma's STACK play. A drilling mechanics focused team created a finite element analysis (FEA) model of the rock cutting process to optimize cutter face geometry for improved cutting efficiency. The new non-planar geometry enabled better cutting efficiency and improved cutter cooling. Multiple lab tests were then used to verify the model's predictions. Results from single cutter lab tests showed an 11% increase in cutting distance as measured in a vertical turret lathe test, a 30% decrease in cutting edge temperature from a pressurized cutting test, and a 10% increase in load capacity compared to a previous non-planar geometry in a face load test. Full-scale pressurized drilling tests in the lab showed that a PDC bit with the new geometry was 15% less aggressive with equivalent-to-lower mechanical specific energy (MSE) when compared to the same PDC bit with a previous generation non-planar cutter. Field tests were conducted with the new non-planar geometry applied to a commercial 0.529 inch [13mm] cutter on a standard 8-1/2 in. drill bit design used in the Meramec Lateral application. The paper reviews in detail three test cases in this multiple bit lateral section using the same bit design with and without the new non-planar cutters. In two test wells, we saw direct improvement of 185% distance drilled on average and an18.3% boost in ROP. At least 17 bit runs have been completed in this application using the new non-planar feature, proving it to be a beneficial enhancement. Similar performance improvement has been observed in other applications as well. The optimized cutter geometry has led to further and faster runs, resulting in significant time savings and improved consistency. The use of advanced cutter geometries provides a significant boost in drilling performance beyond that normally achieved through fixed cutter bit design optimization and materials improvements.
- North America > United States > Oklahoma > Kingfisher County (0.34)
- North America > United States > Oklahoma > Canadian County (0.24)
Robust MMH Drilling Fluid Mitigates Losses, Eliminates Casing Interval on 200+ Wells in the Permian Basin
Offenbacher, M.. (AES Drilling Fluids) | Erick, N.. (AES Drilling Fluids) | Christiansen, M.. (AES Drilling Fluids) | Smith, C.. (AES Drilling Fluids) | Barnard, T.. (AES Drilling Fluids) | Farrell, R.. (AES Drilling Fluids)
Abstract Mixed metal hydroxide (MMH) drilling fluid technology dates back nearly thirty years (Burba III et al. 1988), but its adoption remains limited by the expertise required to deploy the system and the sensitivity of the system to contaminants. In the Permian Basin (specifically the Delaware Basin), a robust MMH formulation mitigates losses and enables control of mud weight through a challenging salt layer of 2,000 to 5,000 feet, eliminating a casing interval. This success has been repeated on over 200+ wells with continuous optimization. MMH systems provide a unique rheological profile as the net positively charged MMH crystals form a complex with negatively charged bentonite, resulting in near instantaneous gel strength at low shear while providing typical flow properties and pump pressures at high shear. MMH applications range from improved suspension during milling operations to minimizing losses in highly fractured formations. Historically, MMH properties break in the presence of anionic materials, such as coal, deflocculants, anionic polymers as well as at elevated salinity. The robust MMH system discussed offers greater stability and lower risk of failure associated with a variety of contaminants. The robust MMH system was deployed to minimize washout in the salt as the highly thixotropic fluid is near static under the low shear conditions near the wellbore. Without the turbulence of conventional fluids, minimal salt incorporation results in near-gauge wellbores and stable fluid density. The original gel system in turbulent flow provides the required properties for drilling, but salt incorporation from the formation causes not only washouts but escalating density. Conventional systems require dilution to maintain density as the salt formation blends with the drilling fluid and elevates density. The MMH system minimizes salt incorporation and allows greater flexibility with increased density as mud density induced losses were less frequent due to its high viscosity at low shear. It is estimated the MMH system performs at +0.2-0.4 lbm/gal higher mud weight than a conventional system before losses occur as the properties of MMH systems inherently limit fluid invasion through fractures. The greater operational window provides more flexibility to insure well integrity. Overall, a combination of proper fluid selection and execution with continuous operational improvement yields great benefits, lowering overall drilling costs 40% and drilling days by 50%. A 50% reduction in dilution volumes and easier fluid management benefits were complemented by lower waste volumes and the elimination of earthen pits.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract Aluminum drill pipe has already been proven as a viable alternative to steel drill pipe when drilling long horizontal wells thanks to its lighter weight that does not compromise resistance to yield and buckling. At the same time, the development of unconventional wells has seen the deployment of numerous technologies to further improve the performance and increase the lateral section to reduce costs. An operator has recently and successfully tested a new aluminum drill pipe with an axial oscillation tool to push further the limits of the drilling system. This paper presents the key findings of the case study using a mixed aluminum-steel string combined with an axial oscillation tool. First, the innovative drill pipe design is presented, followed by lessons learned during rig operations regarding pipe handling practices, rig compatibility and pipe inspection. Then, results of the drilling simulations performed during the well planning phase are presented. This modeling led to an optimum drill string design associating the steerable mud motor assembly, aluminum drill pipe, axial oscillation tool and steel drill pipe. The number and placement of aluminum drill pipe along the string was key to reducing friction and improving weight transfer between the bit and the axial oscillation tool. Through extensive modeling and field data interpretation, this paper presents the comparison of the overall drilling performance between steel only and aluminum-steel drill pipe strings, and provides metrics in terms of weight transfer and rate of penetration improvement. This innovative and promising drill string design opens the doors to set new limits in terms of horizontal departure.
- North America > United States > Texas (0.46)
- North America > United States > Colorado (0.28)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > Laramie Basin > Niobrara Formation (0.99)
- (2 more...)
- Well Drilling > Drillstring Design > Drill pipe selection (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Equipment (1.00)