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.
Use of diverters for altering fluid distribution among created hydraulic fractures in horizontal wells has gained popularity in recent years, both for initial and re-fracturing treatments. Aims in initial fracturing treatments have included creating more uniform distribution of slurry within the created fractures, increasing stage efficiency by reducing the number of pumping stages while increasing the number of clusters per stage, increasing the number of fractures created in openhole completions, reducing interactions between fractures in adjacent horizontal wells, etc. In re-fracturing treatments, a popular application is for altering fluid distribution in wells re-treated without isolation between stages (Pump & Pray/Bullheading) with the intent of increasing the number of re-activated fractures and initiating new fractures through added perforations.
Engineering analysis of the mechanics of fluid diversion has not received the same degree of attention as its use. The reported discussions are often limited in their scope, two-dimensional in structure, and somewhat speculative in their conclusions.
This paper divides the targets of diversion into three categories; at the wellbore/perfs, near wellbore, and deeper inside the fracture. It divides the types of diverters into three categories, mechanical, solid particulate (including proppants), and chemical. The applications are divided into two categories, initial and re-fracturing, together with highlighting their differences and requirements for successful diversion. The paper discusses how presence of proppant changes the fluid distribution in favor of more conductive perforations. It considers the fracture as a three-dimensional structure, extending on both sides of the wellbore. It describes how different diverting agents cause fluid redistribution between the fractures, and the important role of proppant in some applications. It shows that as the target of fluid diversion moves away from the wellbore the chances of its success become smaller and more unpredictable, while also the time before effective diversion takes place becomes longer.
Comprehensive understanding of the mechanics of fluid diversion helps in the selection of the type of diverter and how best to deploy it for achieving specific objectives and results.
Ryan, M. (Baker Hughes, a GE Company) | Gohari, K. (Baker Hughes, a GE Company) | Bilic, J. (Baker Hughes, a GE Company) | Livescu, S. (Baker Hughes, a GE Company) | Lindsey, B. J. (Baker Hughes, a GE Company) | Johnson, A. (Murphy Oil Company) | Baird, J. (Murphy Oil Company)
Development of unconventional reservoirs in North America has increased significantly over the past decade. The increased activity in this space has provided significant data with respect to through-tubing drillouts which had previously not been attainable. This paper is focused on using the field data from the Montney and Duvernay formations along with laboratory data and numerical modeling to understand the hole cleanout associated with through-tubing drillouts of frac plugs.
Initially, an extensive full-scale flow loop laboratory testing program was conducted to obtain data on debris transportation for hole cleanout during through-tubing applications. The testing was conducted on various coiled tubing (CT)-production tubing configurations using various solid particles. The laboratory data was used to develop empirical correlations needed for a transient debris transport model. This model was then used for frac plug drillouts to ensure successful hole cleaning in actual field applications. Computational fluid dynamics (CFD) modelling was also used to further understand and quantify the differences between the laboratory data, field data and transient debris transport model results.
The objective of the work conducted was to gain a better understanding of debris transport and validate the empirical modelling approach developed for hole cleaning. The validation process was conducted in several stages. The first stage was to validate the laboratory data against the Montney and Duvernay field data. The second stage was to verify the results obtained from the empirical model against the results obtained from a computational fluid dynamic model. The results from both modelling approaches were lastly compared to the field data. All these results challenge the current industry's understanding and best practices for through-tubing drillouts in the Montney and Duvernay formations. With the contentious increase of lateral lengths and higher stage counts, the process of drilling out frac plugs has become more complex. This study explicitly benefits all operators in their ever-increasing need to understand their frac plug drillout operations to ensure efficient, cost effective, and most importantly, consistent and repeatable results.
While efficient results for frac plug drillout operations have been accomplished to date, the on-going feedback from the field has been the requirement to produce repeatable drillouts. This paper is the first to show a holistic approach for obtaining a transient debris transport model used for through-tubing drillouts of frac plugs. The novelty also consists of the transient debris transport model validation through laboratory data and actual Montney and Duvernay field data.
Williams, Ryan (Schlumberger) | Artola, Pedro (Schlumberger) | Salinas, Javier (Schlumberger) | Mirakyan, Andrey (Schlumberger) | MacKay, Bruce (Schlumberger) | Hoefer, Ann (Schlumberger) | Kraemer, Chad (Wisconsin Proppants) | Reese, Harrison (PRI Operating) | Roybal, Zack (PRI Operating) | Williamson, Brant (PRI Operating)
Use of regional sand in the Permian Basin dramatically increased in 2018. Regional or in-basin sand is often perceived as lower quality compared to northern white sand (NWS); however, its use is fairly new, and production data has not been available to determine if, or in what cases, higher quality matters. This paper presents the results from a production comparison of Permian Basin wells that were hydraulically fractured with NWS and regional sand or both.
A dataset consisting of approximately 450 wells completed with NWS or regional sand or both within the Delaware and Midland Basins was studied to determine the relationship between production performance and sand type (or quality). To evaluate the effect of sand quality in well production, the dataset was divided in smaller groups of wells with similar reservoir characteristics and completion practices. The initial phase of the study was completed using public domain production data, while the second phase focused on the development of regional reservoir models to forecast production of wells using NWS or regional sand or both.
When analyzing an area containing sufficient wells for a reliable comparison, the survey revealed no statistically significant difference in production for wells that used NWS versus regionally sourced sand. Models were built to predict differences in the production performance of each sand type. These models take into account and demonstrate the effects of differences in sand properties, as well as the impact of the favorable economics associated with regional sands. It was confirmed with the study that the sand type is not a critical factor in regards to production performance when completing wells that are hydraulically fractured in ultralow-permeability nonconductivity-limited reservoirs.
This paper presents an early look at the production numbers of West Texas wells completed with regionally sourced sand in the Permian Basin. The results of the study will encourage operators to further contemplate the use of regional sand when completing wells in ultralow-permeability shale reservoirs. This dataset will continue to evolve and reveal the effects of regional sand over the life of the well; this will be presented in a future paper.
With the industry shifting gears toward pad development there has been a significant increase in operator press releases to stockholders expressing concern about fracture driven interactions (formerly called "frac hits") within a drilling spacing unit (DSU) (
Depletion Mitigation Opportunities Depletion Mitigation Results Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap
Depletion Mitigation Opportunities
Depletion Mitigation Results
Infill Well Asymmetric Frac in Toe Stage with Depleted Primary Well Overlap
Historically, refrac operations in horizontal organic shale wells have had unpredictable production results, with the industry moving toward mechanical isolation following an often painful history that included single stage "pump and really pray" treatments with no diversion to "pump and pray" with chemical or ball sealer diversion. While results from mechanical isolation have been more consistent than these first two methods (
The need for monitoring individual well production in unconventional fields is rising. The drivers are primarily related to accurate reporting for production allocation between wells. The main driver in North American operations for a meter-per-well flow rate monitoring has been the need for accurate per well production accounting due to the complexity of the land-owner interest.
There are additional benefits from the monitoring of early decline and determination of the transient evolution of the reverse productivity index (RPI) to evaluate the well performance. The availability of long-term rate transient data supports decline analysis and rate transient analysis, leading to better understanding of the estimated ultimate recovery (EUR), which may drive the selection of infill drilling locations. Finally, the identification of interference between flowing wells can help mitigate the issues of parent/child wells.
A specific case in the Eagle Ford is the systematic deployment of full gamma-spectroscopy multiphase flowmeters at well pads. This intelligent pad architecture consists of one multiphase flowmeter per well and a production manifold that enables commingling of the production to a single flowline connected to the inlet manifold of the production facility.
The rationale of the decision for the installation of such solution in lieu of a metering separator per well is based on the evaluation of the impact of this technology on capex and opex reductions.
Several lessons learned are provided. They include a discussion of the change management issues related to the installation of the meters, the modifications necessary to the production facility at the receiving side, and the data management and data analytics that were enabled from the gathering of systematic, continuous, and high-resolution measurements.
The impact of the installation of the meters in the field is noticeable and quantifiable. with several prior wells used as a benchmark. The effects are not limited to cost reduction, but also lead to an increase in production related to the release of operational crews from daily well testing tasks that used to be necessary. The data quality and coverage are also increased.
A few suggestions are made concerning optimization of the deployment and use of remote monitoring options for enhanced efficiency. Automated data workflows are also discussed.
The reduction of HSE risks through a better management of field operators is also assessed.
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.
Potapenko, Dmitriy (Schlumberger) | Theuveny, Bertrand (Schlumberger) | Williams, Ryan (Schlumberger) | Moncada, Katharine (Schlumberger) | Campos, Mario (Schlumberger) | Spesivtsev, Pavel (Schlumberger) | Willberg, Dean (Schlumberger)
Highly efficient multi-stage hydraulic fractured horizontal wellbores are the dominant completion method for many basins worldwide. One potential weakness of multi-stage hydraulic fracturing is that the later stages of the completion workflow – frac-plug drill out (FPDO) and flowback – cause large pressure fluctuations and transient flows through the perforation clusters that coincide with a period of low closure stress in the fractures. The proppant packs in the fractures during this period are fragile and prone to failure. Previously reported results show that flowback and initial production practices have a major impact on proppant production, maintenance and disposal costs and the subsequent well performance. In this paper the results from over 200 FPDO and flowback operations from the United States and Argentina are reviewed. These results show that maintaining a balanced flowrate during FPDO operations is critical for minimizing inadvertent damage to the hydraulic fracture network.
The FPDO flowrate balance is the difference between the coiled tubing injection and annular return flowrates. The magnitude and sign of the balance corresponds to the instantaneous flowrate through the open perforation clusters into or out of the hydraulic fracture network. A positive balance rate, or overbalance, injects fluid into the fracture system. A negative balance rate, or underbalance, produces stimulation or formation fluids from the fracture network. Sudden changes between these two regimes creates local flows that can be severe enough to flush large quantities of proppant out of the fractures. Our results show that high-frequency multiphase flowmeters simplify the process of maintaining balance (no inflow, no outflow). Furthermore, close monitoring of any imbalance that develops, and rapid control of the surface choke and injection rate, can provide for an efficient operation while protecting the integrity of the fracture system.
Early monitoring of flowback and production with a high frequency flowmeter was shown to be extremely useful technique for optimizing well productivity during well clean-up. This paper also shows how a dual energy gamma ray multiphase flowmeter successfully quantified proppant produced during FPDO and flowback. Examples of the dynamics of sand production are shown, as well as correlations to events of excessive underbalance conditions.
At the end of the paper we show that most of the highlighted problems can be solved through making changes to the well construction workflow and accounting for relationships between various well operations. Incorporation of this workflow enables early prediction of well performance issues and their efficient resolution.
This review is based on latest application of nanoparticles in hydraulic fracturing, and their feasibility as compared to other conventional methods. Focusing on technical, economic, mechanisms and direction of future research. Current status and advancement give a promising future application by using unique properties of nanomaterials such as small sizes, stability, magnetic properties and surface area which are yet to be exploited to full potential. Nano materials can be inculcated in drilling in all forms. From acting as additives in drilling mud there by enhancing density, gel breaking strength, viscosity, acting as a proppant, cross linking agent etc.
There are certain problems which are difficult to overcome using macro and micro type additives due to limitations in physical, chemical and environmental characteristics. Hence, the scientists are looking for such smart fluids which can overcome these limitations. Compared to their parent materials, nanoparticles can be modified physically, chemically, electrically, thermally, thermodynamic properties and interaction potential of nanomaterial. However more investment, work and pilot projects are required to understand properties of nanomaterials at reservoir temperature and pressure.
Nanomaterials such as aluminium oxide, zinc oxide, copper oxide, silicon dioxide, low cost carbon nanotubes, fly ash nanoparticles in unconventional reservoirs need to be further researched. Moreover, focus should be put on economic analysis, performance at reservoir conditions, cross linking and agglomeration properties, wettability alterations, interfacial tensions properties. The enhanced hydrocarbon recovery from unconventional reservoirs through wettability alterations and interfacial tension decrement by nanomaterials and combined use of fracturing fluid system comprising of VES, foams, proppants gives a promising future application.
Traditional sand control sizing has typically been based on "standard", wide-sieve gravel distributions (i.e. 20/40, 16/30, etc). Historic sand retention testing has therefore been limited to these standard gravel (i.e. proppant) sizes. With the emergence of new proppant technologies, extensive testing has recently been performed to evaluate the impact of mono-sieved gravel on sand retention performance.
Sand retention testing was performed using a number of industry test protocols [
Comparison of the mass of produced sand through various combinations of formation/gravel are useful in identifying the preferred gravel to manage solids production. This study will show that sand control performance of mono-sieved gravel is comparable to that of standard-sieve distribution gravel. This is illustrated by comparing the mass of produced sand and measurement of permeability in the various formation/gravel combinations. The paper will demonstrate that numerous "rules of thumb" employed for gravel sizing (including use of "Saucier's ratio") during the gravel- and frac-pack design process can be applied to any sieve distribution gravel, whether standard- or mono-sieved. In addition to the test results, this paper will reference multiple GOM applications with frac-pack completions in which sand control is performing as designed using mono-sieved gravel.
This paper is critical for all completions engineers who are designing gravel or frac-pack completions. Sand retention testing on mono-sieved gravel is novel, and these results complement existing testing. The results of this testing have already been applied by several exploration and production companies, and this paper will allow others to benefit from the work.