Major performance challenges for deepwater applications from a drill bit standpoint were identified as (1) High surface torque in salt is one of the major ROP limiters. (2) Inability to control depth of cut in soft rocks including shale and salt and when drilling in interbedded formations results in torsional oscillations and stick-slip. (3) Improper combination of bit and reamer induces drillstring vibrations. This paper presents the development of new drill bit technologies combined with a new system matching analysis package to address those problems.
Salt mechanical behavior was evaluated using triaxial testing under confining pressures up to 5,000 psi. Full scale pressurized testing was then conducted to evaluate salt drilling behavior versus rock characteristics. The following specific challenges were addressed: Non-planar PDC geometries were tested in salt, among other rocks, to identify a geometry which results in maximum increase in ROP at any given torque. New insert shapes were developed and tested for more effective and accurate depth of control. A full drillstring analysis model was developed with the ability to predict downhole and surface torque and WOB as well as drillstring dynamics, torque, and drag.
Non-planar PDC geometries were tested in salt, among other rocks, to identify a geometry which results in maximum increase in ROP at any given torque.
New insert shapes were developed and tested for more effective and accurate depth of control.
A full drillstring analysis model was developed with the ability to predict downhole and surface torque and WOB as well as drillstring dynamics, torque, and drag.
The new shaped cutter full scale pressurized test resulted in an increase in ROP/torque ratio throughout the different rock and a 28% increase in salt. The cutter also increased ROP/WOB ratio by 42%. Furthermore, the new insert shapes proved to be more effective in controlling depth of cut, resulting in an extra 35% reduction in torque/WOB ratio compared to standard insert shapes.
The project is now in field evaluation and the new drill string analysis tool has been applied to several field applications including some in the Middle East, North Sea, Gulf of Mexico, and the Caribbean for different purposes. Some of those purposes include buttonhole assempbly (BHA) selection for given bit and reamer, bit selection for a given BHA design and reamer, and drilling parameter optimization for a given BHA design, bit, and reamer. New insert shapes were run in multiple applications in North America, including in North Dakota and Oklahoma, with promising results proving that although the project was focused on deepwater drilling challenges, the novel solutions are applicable to a wide range of applications.
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 (Anadarko Petroleum Corporation)
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.
This paper presents a new workflow for monitoring drilling efficiency in real time during drilling operations. Based on a bit-rock interaction model, the new workflow provides parameter estimations, such as bit wear and in-situ rock strength, obtained from typical real-time drilling measurements. The model can be used to predict rate of penetration (ROP) ahead of the bit, optimize drilling operating parameters, and determine the potential benefits of tripping out to change the bit.
The new approach presented here was initially tested in a laboratory-based drilling rig. Once these tests confirmed the theory, the technique was then validated on several operations to monitor and optimize drilling efficiency.
The workflow presented in this paper is a powerful method for monitoring real-time drilling efficiency through estimating bit wear, in-situ rock strength, and future ROP. This new method uses a novel approach that combines time-based and depth-based drilling data and innovative data processing algorithms to further constrain and enhance these estimated parameters. The new method is totally automatic and has been shown to facilitate optimizing drilling efficiency in real time.
Percussion drilling system, combining a 6 in. mud hammer with specific hammer drill bits, has been developed to increase drilling performances in hard formations. This system is based on a high-power down-the-hole hammer (Power output of 30 kW), capable of delivering high-energy impacts at high frequency (blow frequency of 35 Hz). Weighted mud pressure is used as a power source, making it fully compatible with current drilling rigs and existing drilling procedures. The drill bit is a key performance element because it is the one that is in contact with the rock and destroys it. It must be designed to optimize the cutting process in its particular environment (energy, rock, pressure, …).
Numerous elementary tests of the insert-rock contact as well as the development of a semi-analytical model of the performances has been performed and devevelopped. It makes it possible to show the importance of the bit design parameters and the need to adapt the bit design to the drilling conditions (rock characteristics as well as hydrostatic pressures or available energy). A new generation of bits optimized for performance has thus been developed.
The 6 in. mud hammer and the new drill bit have been then tested on a full scale drilling test bench in different types of formations and with pressure conditions representative of deep drilling. The performances comparison with roller cone bit showed an improvement of 100 to 300% of Rate of Penetration (ROP). The set was ultimately used in field drilling operations and validated the large improvement in ROP of 300%.
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. (Cimarex Energy Co.) | Cantrell, B. (Cimarex Energy Co.) | Bryant, S. (Cimarex Energy Co.)
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 205% distance drilled on average and a 33.5% 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.
Wellbore stability in shale is often hampered by the detrimental effect of existing weak bedding planes on the strength of the rock surrounding the wellbore against shear failure. This paper presents results from a formal closed-form analytical solution to the wellbore stress problem that incorporates rock failure along weak bedding planes. The solution is used for a case study of a highly inclined well section in a laminated layer of troublesome shale with a strike-slip faulting regime above the target formation in the Latin America region.
Tonner, David (Diversified Well Logging) | Swanson, Aaron (Diversified Well Logging) | Hollingshead, Ron (Diversified Well Logging) | Hughes, Simon (Diversified Well Logging) | Seacrest, Stephen (PetroLegacy Energy) | McDaniel, Bret (PetroLegacy Energy) | Leeper, Jay (Solid Automation)
From the very early days of oil and gas exploration, appraisal and development drilling, samples have been collected at the rig by mud logging personnel to conduct a preliminary geological analysis of the rock being drilled. This collection typically involves a sample collection recipient, board or bucket to collect a sample of rock over the desired interval. The sample is then sieved and cleaned in the appropriate way depending on the type of drilling fluid being used. As penetration rates have increased in some instances to more than 400 ft. / hr. the sample resolution has deteriorated exponentially. From an ergonomics perspective, the highest frequency to which a person onsite can collect a sample is once every 20 minutes. At 300 ft. / hr. this translates to 100 ft. of drilled rock. A new device has been developed and deployed which automates this manual process and thus ensures faster and more accurate collection of geological samples of the drilled rock interval. Sample resolutions of 5ft rock intervals have been attained at 400 ft./ hr. This technology has provided an important technological breakthrough and enables reduction of personnel at the rig site with a subsequent reduction in cost and HSE risk, particularly in areas of H2S. It further has provided for the potential integration with Measurement while drilling personnel. For both conventional and unconventional play development, this has provided oil and gas operators with an important and cost and risk reducing modus operandi compared to conventional drilling and evaluation techniques. The tool was deployed for an operator in West Texas where both manually collected traditional mudlog samples and automatically collected samples were taken. The samples were analyzed and compared for rock content. In addition, comparisons were made between point sampling with the automated system versus samples collected over a defined interval manually. Results of these comparisons will be presented.
A new method of automated drill cuttings sample collection has been successfully deployed. The new method provides a step change improvement in accuracy and resolution for sampling the rock record during drilling.
Additional data of the rock record provides potential insights to optimize wellbore placement and provide increased geo-mechanical data to optimize completions.
Oilfield economic conditions today continue to emphasize the need to recognize and respond to drilling dysfunctions quickly to maximize performance and minimize well costs. It is important for drilling engineers planning wells to fully comprehend each dysfunction in order to develop a means to mitigate their impact. As progress is made in this effort, it has become increasingly clear that many issues facing the drilling industry cannot be solved or solutions implemented with traditional drilling technology and platforms. The automation of drilling data collection and control systems response is increasingly becoming a key aspect of advancing many aspects of drilling performance.
SPE's Drilling Systems Automation Technical Section (DSATS) now enters its third year of an international competition for universities to design and build a small drilling rig that can operate hands-free in an unknown formation. Much like engineers in the field, students from each team must develop technical skills to understand the drilling dysfunctions that affect their rig's performance and calculate their impact on drilling performance. For the first time, in the 2017 competition, students must design and build a downhole sensor integrated into their control scheme. They have applied several different sensor types and unique telemetry techniques in custom-machined bottom-hole assemblies (BHA) that follow a 1.125 in (28.5mm) bit. The collected data is being used for vibration mitigation in real-time without human intervention.
The teams realize that the measurement and control aspects of drilling are as important as the equipment design, so they must model the drilling-states to determine appropriate response algorithms. Issues must be identified, and drilling parameters adjusted before dysfunctions severely limit performance. Teams often conduct a series of structured tests in various rock types to pre-tune their drilling algorithms. With improved state-detection algorithms and new optimization techniques, the drilling parameters that maximize performance are immediately calculated and implemented. DSATS intentionally challenges each team by choosing a thin-walled pipe which limits the ability to apply weight on the bit (WOB), ultimately generating an environment that promotes bit whirl. DSATS also provides an unknown rock sample of varying material, formation dips and other "surprises."
This paper presents the results of on-site testing of the winning team, Texas A&M University, who drilled a high-quality wellbore in the shortest amount of time. It also details the decision-process for the rig's design, based on background lab tests and engineering calculations.
There are many causes for injection wells to perform poorly; in this paper, we address the effect of residual hydrocarbons near the wellbore, which reduce the rock's effective permeability to brine, thus decreasing well injectivity. Immobile hydrocarbon saturations are found around injection wells when these are drilled above the water-oil contact level, which arises when a producer well is switched to injection, or the formation's underlying aquifer is hard to reach. Furthermore, oil can accumulate around a wellbore when produced brine containing even trace amounts of hydrocarbons is used as the injection fluid. To address this problem, it is possible to flush out hydrocarbons around the wellbore by periodically injecting small amounts of surfactants for short periods. This technique leverages the capillary desaturation behavior of a multi-phase fluid mixture, wherein increasing the capillary number of a rock-fluids system beyond a threshold value will decrease the residual hydrocarbon saturation. The capillary number, which characterizes the ratio of viscous to capillary forces, can be increased by injecting surfactant loaded brine; this reduces the hydrocarbon-brine interfacial tension which reduces the capillary forces, decreases the system's residual hydrocarbon saturation, and increases the brine's effective permeability. To efficiently assess the impact of a surfactant flush, we perform digital rock multi-phase flow simulations on Berea and Fontainebleau sandstones at different capillary numbers. The simulations provide the residual hydrocarbon saturation and the brine's effective permeability as a function of capillary number, which is related to the amount and type of surfactant. These results are then used in a radial wellbore simulation to compute the attainable injection rate for a maximum allowable pressure drop. Since the largest pressure drop occurs very close to the wellbore, the surfactant flush is very effective even though it only affects a few feet from the wellbore. For the specified scenario we observe a potential well performance improvement ranging between 20% and 150%. By using digital methods, this study was performed in about two weeks, at lower cost than Special Core Analysis Laboratory (SCAL) physical testing, and with ideal reproducibilty since the capillary number can be modified without affecting the sample or any other aspect of the test procedure.
Formation damage from mud invasion is a complicated process that is influenced by mud type, downhole fluid particle size distribution (PSD), mud rheology, rock type, lithology, permeability, drill pipe rotation, geochemical factors, pressure, and temperature. Many of these variables are often ignored, simplified, or underestimated. Thus, their individual and combined effects on formation damage is not well understood. Among these factors, the porous media complexities play a key role in determining the extent of drilling mud damage to the formation.
This paper is focused on characterizing water based mud's (WBM) invasion and damage to different rock cores representing various lithologies, under simulated dynamic wellbore condition. The experiments performed in this study were selected from a statistical design of experiment method. Based on formation damage relevance, the following factors were considered and varied: pore throat diameter of homogenous porous media (ceramic filter tubes), lithology type, and temperature. The levels of each factor were determined from a mud invasion data base considering high and low limits. Other constant factors were rotary speed, type of lost circulation material (LCM), concentration of LCM, and pressure. An LCM was carefully added to the WBM to reduce the fluid's invasion. Dynamic wellbore condition (pipe rotation only) was simulated with a drilling simulator, capable of rotating a shaft that is centered between the inner diameter of the damaged porous media. Using this approach, the formation damage profile of the WBM on four different lithologies was investigated. The results revealed that rock permeability and porosity are critical factors that control mud invasion, damage propensity, and filter cake permeability profile. Statistical analysis showed that increase in temperature can significantly increase the degree of mud solids cross flow and fines mobilization through the porous media. Thus, leading to the reduction of formation permeability. In a radial system, ceramic filter tubes representing homogenous porous media are often used to quantify mud invasion. However, further investigation revealed no significant change in the damage profile exhibited by the two (5μm and 20μm) pore throat diameter filter tubes used in this study. These filter tubes are typically calibrated to match permeability values of actual rocks, but are not true representation of lithology complexities. The novelty of this study lies in integrating different constant and varying mud invasion factors in relation to the damage of four lithology types.