The 12 ¼" section in the western desert, Bapetco concision is challenging to be drilled as of the highly interbedded carbonate and shale formations, which are known to exhibit high levels of vibrations (torsional and lateral) associated with high drilling torque. Such high drilling torque lead-to increasing the Mechanical Specific Energy (MSE), reduction in Rate Of Penetration (ROP) and early dull for used bits. While in some cases it can even lead to twist-off incidents and major Non-Productive Time (NPT) events. Customer NPT can cost up to $ 450k in case of sidetracking the well. In case the Bottom Hole Assembly (BHA) stands the vibration level, the parameters would have been controlled losing ROP which resulting in lost time that cost at least $ 35K. The solution of adjusting the depth of cut downhole (Self-Adjusting) which have been newly introduced to the market targeting to decrease downhole vibrations, specially torsional vibrations and allow smoother transition between lithologies with different compressive strength and help in a smooth transition between the different layers while optimizing the depth of cut control When the self-adjusting feature engages with rock for steady state drilling, the feature gradually retracts, controlling DOC to find the optimal exposure of the element for the current drilling parameters and formations. As dynamic instabilities occur, the self-adjusting feature reacts at fast time scales to mitigate the event. This should result in optimizing the bit response to deliver the best performance real time, decreasing the torsional vibration, NPT & MSE. This will lead to increase the drilling efficiency. The 12 ¼" PDC bit with the self-adjusting was tested with one Shell/Bapetco in the western desert wells, resulting in decreasing the vibration levels, decreasing the MSE hence increase the ROP 57% compared to average of the field which resulted in significant reduction to the drilling cost compared to the offset wells while achieving 35K of savings compared to the best offset Below will present how the latest self-adjusting PDC technology had a significant impact on drilling time and cost savings by mitigating drilling dysfunctions that could result in unplanned trips and drilling inefficiencies if not addressed in a timely manner 2 SPE-197905-MS
Maalouf, Janine (Schlumberger) | Benny, Praveen Joseph (Schlumberger) | Cantarelli, Elena (Schlumberger) | Al-Hassani, Sultan Dahi (ADNOC Offshore) | Altameemi, Ibrahim Mohamed (ADNOC Offshore) | Ahmed, Shafiq Naseem (ADNOC Offshore) | Khan, Owais Ameer (ADNOC Offshore) | Al Hammadi, Mariam Khaleel (ADNOC Offshore) | Zakaria, Hasan Mohammed (ADNOC Offshore) | Aboujmeih, Hassan Fathi (ADNOC Offshore)
Ultrahigh-resolution electrical images (UHRIs) acquired with logging while drilling (LWD) tools have brought to light different side effects of using drilling tools such as rotary steerable systems (RSSs) and bits when drilling a horizontal borehole. This paper will go through the extensive analysis and simulations that followed, gathering data from almost thirty wells, to try and understand the root causes behind these side effects, along with the actions put in place to mitigate it. UHRIs were used while drilling a 6-in horizontal hole to achieve a 100% net-to-gross and perform advanced formation evaluation to optimize well production. Surprisingly, these images revealed more details: wellbore threading–a type of spiral–inside the formation. To understand the cause behind such marks, RSS and bit data was gathered from around thirty wells, compared, and analyzed. Simulations were run over months, considering rock types, drilling parameters, and bottom hole assembly (BHA) design to reproduce the issue and propose the best solution to prevent these events from reoccurring. After the data compilation, a trend emerged. Wellbore threading was observed in soft, high-porosity reservoir formations. It also appeared in tandem with controlled rate of penetration (ROP), low weight on bit (WOB), and a low steering ratio. At this point, advanced analysis and simulations were needed to determine the root cause of this phenomenon. A Finite Element Analysis (FEA) based 4D modeling software showed that the bit gauge pad length, combined with the RSS pad force, contributed to this threading. A pad pressure force higher than 7,000 N in conjunction with a short-gauge bit increased the likelihood of having this borehole deformation. Simulations comparing different size tapered and nominal bit gauge pad lengths were run to determine the effect on the borehole and on the steerability. Bit design is directly linked to the wellbore threading effect. It is more pronounced when associated with a powerful rotary steerable system and in a soft formation environment. However, altering a specific bit design can have a direct and undesirable effect on the steerability of the BHA. UHRI revealed details of borehole deformation that new drilling technologies are causing. It enabled an in-depth analysis of the different causes behind it, revealing ad-hoc solutions.
Horizontal wells are being drilled in more challenging environments such as through thin formation layers, unpredictable geology, and unknown fluid movement. Detailed evaluation has a direct impact on the completion approach. But we also need to drill faster and more efficiently. The wellbore threading caused formation damage that masked information needed for formation evaluation. In a novel application of UHRI data, simulations gave birth to information which has been lacking and incentivized the development of new, formation-friendly technology.
Abbas, Ahmed K. (Iraqi Drilling Company) | Assi, Amel H. (Baghdad University) | Abbas, Hayder (Missan Oil Company) | Almubarak, Haidar (King Saud University) | Al Saba, Mortadha (Australian College of Kuwait)
The drill bit is the most essential tool in drilling operation and optimum bit selection is one of the main challenges in planning and designing new wells. Conventional bit selections are mostly based on the historical performance of similar bits from offset wells. In addition, it is done by different techniques based on offset well logs. However, these methods are time consuming and they are not dependent on actual drilling parameters. The main objective of this study is to optimize bit selection in order to achieve maximum rate of penetration (ROP). In this work, a model that predicts the ROP was developed using artificial neural networks (ANNs) based on 19 input parameters. For the modeling part, a one-dimension mechanical earth model (1D MEM) parameters, drilling fluid properties, and rig- and bit-related parameters, were included as inputs. The optimizing process was then performed to propose the optimum drilling parameters to select the drilling bit that provides the maximum possible ROP. To achieve this, the corresponding mathematical function of the ANNs model was implemented in a procedure using the genetic algorithm (GA) to obtain operating parameters that lead to maximum ROP. The output will propose an optimal bit selection that provides the maximum ROP along with the best drilling parameters. The statistical analysis of the predicted bit types and optimum drilling parameters comparing the actual flied measured values showed a low root mean square error (RMSE), low average absolute percentage error (AAPE), and high correction coefficient (R2). The proposed methodology provides drilling engineers with more choices to determine the best-case scenario for planning and/or drilling future wells. Meanwhile, the newly developed model can be used in optimizing the drilling parameters, maximizing ROP, estimating the drilling time, and eventually reducing the total field development expenses.
Pelfrene, Gilles (Varel International Energy Services) | Al-Ajmi, Hadi (Kuwait Oil Company) | Bashir, Jomah (Kuwait Oil Company) | Al-Otaibi, Fahad (Kuwait Oil Company) | Al-Nuaimi, Ahmad (Kuwait Oil Company) | Al-Jiran, Hamad (Kuwait Oil Company) | Baroun, Ahmad (Kuwait Oil Company) | Al-Kandari, Abdulaziz (Kuwait Oil Company) | Huseen, Talal (Kuwait Oil Company) | Mikhail, Boktor (Varel International Energy Services) | El-Genidy, Ehab (Varel International Energy Services) | Reboul, Sebastien (Varel International Energy Services) | Carlos, Julien (Varel International Energy Services)
Simulating the mechanical response of PDC drill bits contains a lot of uncertainties. Rock and fluid properties are generally poorly known, complex interactions occur downhole and physical models can hardly capture the full complexity of downhole phenomena. This paper presents a statistical approach that improves the reliability of the PDC bit design optimization process by ensuring that the expected directional behavior of the drill bit is robust over a well-defined range of drilling parameters.
It is first examined how uncertainty propagates through an accurate bit/rock interaction model which simulates numerically the interaction between a given PDC drill bit geometry and a given rock formation, both represented as 3D meshed surfaces. Series of simulations have been launched with simulation parameters defined as probability density functions. The focus has been set on directional drilling simulations where the drill bit is subjected to significant variations in contact loads on gage pads along its trajectory. A global sensitivity analysis has also been performed to identify the key parameters which control drilling performance.
Directional system parameters are critical in terms of steerability and tool face control, particularly in high dogleg severity applications. Based on these simulations, a statistical optimization strategy has then been implemented to ensure that the directional performance of the drill bit remains effective under a given uncertain drilling environment. Statistical analysis combined with drilling simulations indicated that ROP improvements could even be achieved without compromising steerability. A balanced bit design was selected and manufactured in an 8 1/2-in. model to drill a 714 ft section of a Kuwait field. The bit was run on a high dogleg rotary steerable system and directional assembly. The bit achieved the high steerability goals required by the application while showing a good compatibility with the directional tool. Moreover, ROP was increased by approximately 27% compared to offset wells, setting a record rate of penetration in the field.
Whereas statistical analyses are commonly conducted in the field of geosciences, it has rarely been applied in the field of drilling applications. The statistical bit design optimization strategy deployed in this work has allowed to improve both the drilling performance of the drill bit and its reliability.
Underbalanced drilling via air drilling is deeply rooted in the Northeast United States due to its distinct geology, high rates of penetration (ROP) and drilling efficiency, and low cost of circulating material. The active drilling programs of several independent operators in the Marcellus and Utica Basins are well suited for air drilling down to the final kick off point by virtue of competent, stable formations, low static reservoir pressures, and manageable water ingress to the wells. Air drilling provides near-atmospheric pressure at the borehole bottom, since there is no fluid column with resulting hydrostatic pressure. The result is very high ROP with essentially 100% drilling efficiency, allowing the completion of intervals in one or two bit runs. A service company deployed a cross-functional product development team to optimize oilfield air bits for these applications over the last two years, resulting in decreased drilling costs through increased performance and reliability.
The oilfield air drilling environment places unique challenges on drill bit design due to the increased risk of downhole vibrations, corrosion, abrasive wear, heat generation, and seal infiltration of very fine cuttings. The application requirements have increased due to deeper intervals requiring passage through multiple high unconfined compressive strength formations, extended tangent angles, and rising input energy levels. Accordingly, enhancements to both the cutting structures and sealed bearing systems were vigorously pursued. Several cutting structure design iterations were evaluated in both laboratory and field tests. A new sealed bearing system was developed and implemented for increased life and reliability. Modifications to the bit body for stability were included, and the bit hydraulics were further optimized.
Through an understanding of the objectives and application challenges, unique solutions were developed for Northeast oilfield air drilling applications. The optimization process for the new air bit designs is described, and the resulting positive performance metrics are presented. Improvements were observed in distance drilled, ROP, seal effective rate, and dull condition. Lessons learned were also used to refine the recommended drilling parameters and practices through the challenging formations encountered in these tangent sections, which can span in excess of 7000 feet. These enhancements all contributed to reduced drilling cost and days per well, for increased rig productivity.
The natural gas fields throughout the Marcellus and Utica Basins in the Northeast U.S. continue to deliver rising total gas production for the U.S. and the world through increased capacities in pipelines and LNG trains. Improved drilling performance as documented in this paper are driving continuous improvement in the overall upstream drilling economics of the region.
Operators face the continuing challenge to improve drilling efficiency for cost containment, especially in deepwater drilling environments where drilling costs are significantly higher. Innovative drilling technologies have been developed and implemented continuously to support the initiative. In many areas of the world, including the Gulf of Mexico (GOM), hydrocarbon reservoirs exist below thick non-porous and impermeable sequences of salt that are considered a perfect cap rock. However, salt poses varied levels of drilling challenges due to its unique mechanical properties.
At ambient conditions, the unconfined compressive strength (UCS) of salt varies between 3,000 to 5,000 psi; however, the strain at failure for salt can be an order of magnitude higher when compared to other rocks. Consequently, during drilling salt's viscoelastic behavior requires that its must be broken with an inter-crystalline or trans-crystalline grain boundary breakage. When compared to other rock types, the unique isotropic nature of salt results in a level of strain that is much higher for the given elastic moduli. This strain level makes salt failure mechanics different from other rock types that are prevalent in the GOM.
Hybrid bits combine roller-cone and polycrystalline diamond compact (PDC) cutting elements to perform a simultaneous on-bottom crushing / gouging and shearing action. Two divergent cutting mechanics pre-stresses the rock and apply high strain for deformation and displacement, resulting in highly efficient cutting mechanics. To meet the drilling objectives, different hybrid designs have been implemented to combine stability and aggressiveness for improved drilling efficiency. An operator, while drilling salt sections at record penetration rates, has successfully used this innovative process of rock failure utilizing the dual-cutting mechanics of hybrid bits. This has resulted in significant value additions for the operator.
This paper analyzes field-drilling data from successful GOM wells and attempts to correlate salt failure mechanics and provide insight into dual-cutting mechanics and its correlation with salt failure. The paper also reviews the drilling mechanics of hybrid bits in salt and highlights importance of dual-cutting mechanics for achieving higher penetration rates in salt through improved drilling efficiency.
Mechanical specific energy (MSE) has been widely used in the industry to monitor drilling efficiency. However, it does not give detailed information about energy flow in the drilling system and lacks the resolution to identify the root cause of energy loss. The drilling operation is a dynamic process. Energy input may be from a surface-drive system (top drive or rotary table) or a mud motor placed downhole. In a perfect world, all of the energy is used to drill the rock. However, some of the input energy may reside in the drillstring as strain and kinetic energy due to the deformation and motion of the drillstring. Drilling energy is dissipated due to shock, vibration, fluid damping, and frictional contact between the drillstring and wellbore. A novel method has been developed to calculate the drilling energy flow in the drillstring and to enable better drilling energy management by maximizing useful energy consumption and reducing energy waste. The method provides a new way to understand and improve drilling efficiency.
The method is based on an advanced transient drilling dynamics model which simulates the full drilling system from surface to bit. The entire drillstring is meshed using 3D beam elements, and its dynamic response history is solved by the finite element method (FEM). The energy input can be calculated from surface drilling parameters, such as torque, rotation speed, flow rate, and motor differential pressure. With the simulated history of forces and dynamics of the drillstring, the corresponding strain energy and kinetic energy of the drillstring can be evaluated. The detailed cutting structure model can provide insight on the energy amount consumed by the rock cutting action of the bit and reamer. Putting all the components together leads to a holistic calculation workflow of drilling energy.
Field case studies were conducted to examine the effectiveness of this method. The studies showed the drillstring strain energy and kinetic energy are good performance indicators for drillstring reliability and stability because these energy variables reflect the severity of loading and vibration in the drillstring. The energy variables possess clear signatures for interpretation of different downhole vibration modes. Currently, the drilling efficiency is normally evaluated by MSE, which represents the amount of energy needed to remove a unit volume of rock using the surface drilling data. In this study, the energy loss is calculated to understand the percentage of input energy dissipated due to the interaction of the drillstring with the environment. In contrast to MSE, the calculation provides a more direct and detailed measurement of drilling efficiency. It gives a methodology for understanding detailed energy flow in the drilling system under different drilling vibration modes. It can be applied to bit selection, bottomhole assembly (BHA) design, and drilling parameter optimization to achieve better drilling energy management and improve drilling efficiency.
The novel approach calculates drilling energy based on the transient dynamics simulation of the full drilling system. It provides a detailed and holistic view of drilling energy input, propagation, and consumption. This method could help identify the inefficient drilling conditions and optimize drilling operation through evaluating and comparing different options.
Aguiar, Romulo (Schlumberger) | Tocantins, João Pedro (Schlumberger) | Marquinez, Victor (Schlumberger) | Baines, Victoria (Schlumberger) | Barreto, Diogo (Schlumberger) | Gozzi, Danilo (Petrobras) | França, Rafael (Petrobras)
After findings were made in the pre-salt province that represented a major discovery for the oil industry, drilling activity in Brazil has been focused primarily on economically viable ways to develop these reserves. The pre-salt cluster is a geological formation that consists of organic microbial carbonates and other sediments. The reservoir poses innumerous drilling challenges, including hard silicate nodules and lowporosity layers, which make the formation strength extremely high. Also, the heterogeneity level of such carbonates (within centimeters) imposes extra challenges, especially on drilling shock & vibration, with low rates-of-penetration (ROP), raising pre-salt well construction costs. To offer a technical solution, the service provider applied an innovative approach based on two pillars: a model-based design approach, leading to two drill bit designs with improved cutting structure resistance, with dynamic stability, delivering the entire section in one bit run with higher ROP. Along with the technology, a new workflow called "stratigraphic zonation for drilling" was implemented. This paper reviews the work covering this new stratigraphic zonation workflow, the development of this virtual drilling scenario and some field results with lessons learned and way forward.
Drillstring vibration is a leading cause of downhole-tool failure and premature wear of downhole equipment. Understanding drilling dynamics, the downhole shock and vibration that occur while drilling, is a crucial step to improving drilling efficiency and reducing nonproductive time (NPT). The variables defining drill-bit performance cover a lot of ground. There is a lot of attention given to cutters studding diamond drill bits, but just as important are what is in the rest of the drillstring and the decisions made by the driller.
Downhole drilling dynamics tools and software can assist in understanding the downhole environment, providing a meaningful avenue for drilling optimization. With rig rates running upwards of a million dollars a day for some operations, shaving even a few minutes off the drilling time can result in tens of thousands of dollars in savings. One of the fundamental ways a drilling engineer can achieve this is through selection of a proper drill bit.