Propellants have been used in oil and gas wells to assist with perforating and creating near-wellbore stimulation. Propellants are electrically ignited in the wellbore at the perforated interval. Upon ignition, they rapidly create a large amount of gas, and the pressurization leads to breakdown of the formation. It has been postulated that the pressurization leads to creation of multiple fractures in the formation. This paper describes an experimental study with a new propellant and aims to understand the pattern of fracture creation with these propellants. The results are also compared with an older generation of propellant tested by Wieland et al. (2006).
A large-scale laboratory test was performed in a sandstone block (30×30×54 in.) with a 2-in.-diameter vertical centralized wellbore extending the full block height. The block was loaded in a polyaxial stress frame. A propellant cartridge was positioned in the center of the wellbore. Small holes were drilled in the rock to intersect the expected primary fracture and were instrumented with high-resolution pressure gauges to enable fracture-timing and -growth-rate analysis. Anisotropic stresses representative of field conditions were applied on the block, and the wellbore was pressurized before ignition.
The propellant ignition produced an initial peak pressure of 5,790 psi in 1.4 ms followed by an oscillatory pattern of pressure increase to a maximum pressure of 6,660 psi before decaying because of fracture growth and gas leakoff. The block was removed from the test frame and cut vertically and horizontally to examine the fracture pattern generated by the propellant. A dominant planar fracture was observed on either side of the wellbore, which propagated in the direction perpendicular to the minimum-horizontal-stress direction. It was verified that the propellant had a much-higher burn rate than the propellant tested by Wieland et al. (2006).
The large-scale block test provides critical insights and data that can serve as inputs to calibrate physics-based models for modeling propellant ignition and stimulation. The results help in understanding the benefits and limitations of using propellants for stimulation.
Research has been dedicated to the development of laboratory-scale simulation devices for studying mechanisms of gas migration. Cement-hydration analyzers (CHAs) are commercially available to assist industry in the design of gas-tight slurries. Although cement slurries under controlled conditions in the laboratory can be gas-tight, the in-situ performance of cement slurries is highly variable and difficult to predict. Therefore, a new approach has been designed to evaluate gas-migration potential under a range of representative borehole conditions. A laboratory-scale wellbore-simulation chamber (WSC) has been developed to replicate hydrostatic-pressure reduction in the cemented annulus and evaluate the potential for gas invasion under a range of borehole conditions. A discussion is presented on the development of the WSC that includes the details of the design and monitoring systems as well as the performance characteristics. Calibration-test results are examined to evaluate the performance of the WSC and the ability of the WSC to simulate in-situ wellbore conditions. Analysis of the results verifies the capability of the WSC in successfully recording the necessary parameters.
Busch, Alexander (Norwegian University of Science and Technology) | Islam, Aminul (Statoil) | Martins, Dwayne W. (Neptune Energy Norge AS) | Iversen, Fionn P. (International Research Institute of Stavanger) | Khatibi, Milad (University of Stavanger) | Johansen, Stein T. (SINTEF Materials and Chemistry and Norwegian University of Science and Technology) | Time, Rune W. (University of Stavanger) | Meese, Ernst A. (SINTEF Materials and Chemistry)
In oil and gas drilling, cuttings-transport-related problems are a major contributor to well downtime and costs. As a result, solutions to these problems have been extensively researched over the years, both experimentally and through simulation. Numerous review articles exist, summarizing not only the research history but also the qualitative effect of individual case parameters such as pump-flow rate, pipe rotation, and rate of penetration (ROP) on cuttings transport. However, comparing different studies is challenging because there is no common reference defined in the form of a typical and representative set of case parameters.
To develop relevant and accurate cutting-transport models, it is critical that both experiments and models are targeting flow cases relevant for respective drilling operations. Development of a clear understanding of the industrial-parameter space, as well as establishing benchmarks, will help achieve a more-concerted effort in development of models and corresponding laboratory experiments.
Other industries have established research benchmarks, such as the “NREL offshore 5-MW baseline wind turbine” (Jonkman et al. 2009) in wind-power research, providing a standardized set of case parameters and profiles, readily available for use to researchers worldwide, and resulting in straightforward benchmarking and validation as well as faster establishment of projects.
For application to the modeling of cuttings-transport phenomena, we propose a methodology for deriving a well-defined and standardized set of geometrical, operational, and environmental case parameters describing various operating points of drilling operations and procedures as well as simplified problems. The methodology is exemplified with an 8.5-in.-section drilling-ahead use case with aggregated wellbore data from the Norwegian Petroleum Directorate (NPD). The relevance and application of the derived parameters are briefly discussed in light of modeling, both experimentally and through simulations. Applying this methodology before any cuttings-transport study may enable a better definition of industry-relevant case parameters.
In Part 2, we will apply and discuss the derived parameter sets in the context of nondimensional numbers for assessment of scalability.
Matsumoto, Keishi (Nippon Steel and Sumitomo Metal Corporation) | Sagara, Masayuki (Nippon Steel and Sumitomo Metal Corporation) | Miyajima, Makoto (Nippon Steel and Sumitomo Metal Corporation) | Kitamura, Kazuyuki (Nippon Steel and Sumitomo Metal Corporation) | Amaya, Hisashi (Nippon Steel and Sumitomo Metal Corporation)
Oil country tubular goods (OCTG) casing and liner wear is a critical problem in today’s drilling environments. To put in place practical countermeasures, it is important to understand its mechanism. This paper presents tribological and electrochemical experiments by use of various OCTG casing materials and environmental liquids, along with the in-situ observation and analysis of the rubbing interface. The results revealed that corrosion-resistant alloys (CRAs) showed an adhesive wear mechanism with relatively high wear rates, whereas low-alloy steels showed an abrasive or a corrosive wear mechanism with mild wear rates. The wear rate had a clear correlation with corrosiveness, where the wear rate increased as corrosion current densities decreased. In-situ observation exhibited that corrosion products γ-FeOOH or Fe3O4 were generated and simultaneously scraped by sliding in the case of carbon steel, whereas no corrosion products were generated in the case of corrosion-resistant alloys. In conclusion, CRAs tend to have metal-to-metal adhesion (scuffing) with iron-based tool material, resulting in a high wear rate. However, low-alloy-steel casing can avoid adhesion by oxidizing its surface, resulting in a mild wear rate.
In the completion of oil and gas wells, successful cementing operations essentially require the complete removal of the drilling mud and its substitution by the cement slurry. Therefore, the displacement of one fluid by another one is a crucial task that should be designed and optimized properly to guarantee the zonal isolation and integrity of the cement sheath. Proper cementing jobs ensure safety, whereas poor displacements lead to multiple problems, including environmental aspects such as the contamination of freshwater-bearing zones. There are a number of factors, such as physical properties of fluids, geometrical specifications of the annulus, flow regime, and flow rate, that can remarkably affect the displacement efficiency. The shape of the interface plays an influential role during the displacement process. For a highly efficient displacement, the interface has to be as flat and stable as possible. However, unstable and elongated interfaces are associated with channeling phenomena, excessive mixing, cement contamination, and, consequently, unsuccessful cementing operations. Thus, the stability of the interface between the two fluids has major importance in cementing applications.
In the present work, a novel method for the prediction of interface instability and displacement efficiency is introduced. Instability analyses of the interface between the two fluids are carried out following the main ideas of the original Rayleigh-Taylor (RT) and Kelvin-Helmholtz (KH) instabilities. Moreover, with the same analyses, optimized designs for the improvement of the displacement process in any specific situation can be proposed. The influence of density, rheological properties, surface tension, and flow rate of the fluids on the instability and shape of the interface, and consequently on the displacement efficiency, is studied. The 3D-computational-fluid- dynamics (CFD) simulations are performed with commercially available CFD software to study several displacement cases. To validate the results, numerous experiments were conducted for fluids with various combinations of physical properties and operational conditions. For one of the inefficient displacement cases, an optimized design is provided on the basis of a study of the instability of the interface, and the improvements are validated by CFD simulations.
The results present the effect of fluid properties, geometrical configurations, and flow rate on the instability of the interface and displacement efficiency. A reasonably good agreement between the results of all approaches presented in the paper is observed, and they all emphasize the importance of the proper selection of fluid properties and flow rates for any specific sequence—to minimize the degree of contamination and mixing.
The discussions and results of this work provide insight into the displacement process, beneficial guidelines for industrial applications, and compelling evidence of the importance of correct predictions and appropriate designs of the displacement of fluids in cementing operations.
One of the important functions of drilling fluids is to form a filter cake, which minimizes leakoff of drilling fluids into the formation. Drilling-fluid invasion can cause formation damage, but good-quality filter cake can reduce such damage. This research focuses on the laboratory techniques and performance results of testing innovative calcium-bentonite-based drilling fluids containing nanoparticles (NPs) for minimizing formation damage during drilling in harsh environments.
A rotational viscometer was used to measure the rheological properties of the tested fluids. Zeta-potential measurements were conducted at different NP concentrations to assess their stability and to investigate the role of charge potential. Indiana limestone outcrop disks were examined as the filter media for both static and dynamic filtration (up to 350°F and 500 psi) using a filter press. The filter cakes were examined using a computed-tomography (CT) scan and scanning-electron-microscopy energy-dispersive spectroscopy (SEM-EDS). Inductively coupled plasma optical-emission spectrometry (ICP-OES) was used to measure the concentrations of key ions in the filtrate fluids.
A reduction of 43% in the filtrate-fluid volume was achieved when adding 0.5 wt% of ferric oxide NPs compared with that of the base fluid. However, using silica NPs led to an increase in the filtrate volume and filter-cake thickness. Using 0.5 wt% of ferric oxide NPs provided less agglomeration and reduced the filter-cake permeability. In addition, the SEM-EDS and ICP-OES analysis showed a replacement of the cations dissociated from the bentonite by NPs, which promoted the formation of a rigid clay-platelet structure. The produced filter cakes consisted of two layers, as indicated by the CT-scan analysis. Increasing the concentration of NPs resulted in an increase in the fluid loss and filter-cake thickness. At a higher NP concentration (2.5 wt%), a third layer of NPs was observed, which adversely affected the filter-cake characteristics, as demonstrated by CT-scan analysis and SEM-EDS elemental mapping. Furthermore, the NP-bentonite fluids had stable rheological properties at different temperatures (up to 200°F) and NP concentrations. In addition, aging these fluids at 350°F for 16 hours showed minor changes in the rheological properties.
This research work provides an experimental evaluation of improved calcium-bentonite-based fluids using NPs under downhole conditions. The ferric oxide NPs have the potential to enhance the properties of calcium bentonite, as a low-cost alternative, to perform well in an application where the higher-value sodium bentonite is commonly used, which could provide more-efficient drilling operations and less formation damage.
Beldongar, Maye (Schlumberger) | Agee, Daniel (Schlumberger) | Kumar, Amrendra (Schlumberger) | Offenbacher, Matthew (Schlumberger) | Flamant, Nicolas (Schlumberger) | Lees, Ashley (Schlumberger) | Gadiyar, Bala (Schlumberger) | Parlar, M. (Schlumberger)
At some stage after drilling to target depth and before pumping the gravel-packing treatment or before putting the well on production, the drilling fluid is typically displaced from the wellbore. Practices in the industry vary significantly depending on the primary drivers of the completion engineers, sometimes with undesirable results. Inefficient wellbore displacements can cause a variety of problems, including increased nonproductive time, reduced well productivity, and incomplete gravel packing through various mechanisms.
In this paper, we detail our best practices to ensure efficient wellbore displacements for sand-control completions on the basis of learnings from more than 500 openhole completions throughout the world from 2013 through 2016. In the design phase, these involve various compatibility tests, some of which are not commonly performed, and/or potential problems that cannot be identified easily when they are performed using conventional test procedures. Additional considerations include the modeling of fluid/fluid displacements and determining the fluid properties, pump rates, and fluid volumes required for effective displacements in a given wellbore geometry and flow paths. On the rigsite, they involve several quality-control tests, some of which have not been implemented previously.
Yield and buckling are independent of hydrostatic pressure. However, leak in a threaded connection depends on hydrostatic pressure, and hence, leak resistance is a function of connector location in the string. It also means that von Mises stress alone is insufficient to characterize connection leak. Like pipe-body yield and buckling, a simple consistent failure theory derived from principles of mechanics is proposed for leak in threaded connections. In addition, the buckling fictitious force is reformulated as a nonfictitious expression to clearly show independence of hydrostatic pressure. Two leak constants—thread modulus and makeup leak resistance—are introduced and evaluated with simple example cases. To quantify results, a 7-in. long-thread-casing (LTC) connection is modeled with the new leak criterion, and results demonstrate that the connection can withstand differential pressures higher than the published ratings because of hydrostatic pressure. A new connection safety factor is defined, and a leak line and a leak circle are developed for graphical purposes to quickly identify critical loads for leak.
Presented here is a case study on the condition and performance monitoring (CPM) of a subsea blowout preventer (BOP) pipe ram. The proposed real-time CPM solution uses adaptive physics-based models that process sensor measurements at the point of origin (known as edge analytics). The adapted model coefficients are treated as a vector, the magnitude of which estimates the degree of health degradation and the phase of which identifies its source. The benefits of using an adaptive model-based approach over traditional machine-based learning and artificial-neural-networks solutions include zero algorithm-training times, broad applicability to BOPs, model modularity, and accurate health-degradation estimates. The proposed CPM methodology is validated on a BOP pipe ram using both operational and simulated data. A sensitivity study of the method to system uncertainty is also presented.
Lost circulation is a time-consuming and expensive challenge, costing the oil and gas industry billions of dollars each year in materials, nonproductive time, and minimized production (Catalin et al. 2003; Fidan et al. 2004; API 65-2 2010). To mitigate lost circulation during cementing operations, a better understanding of how wellbore-strengthening mechanisms apply to cement slurries is necessary. The ability to control cementing-fluid properties to strengthen the wellbore and minimize losses during cementing operations is imperative for achieving adequate zonal isolation.
A field analysis was performed to understand the start of lost circulation during different phases of drilling and primary cementing. Offshore wells from four different locations were studied: Gulf of Mexico (GOM), the UK, Angola, and Azerbaijan. In parallel, laboratory research was performed to understand the behavior of cement slurries in controlled lost-circulation scenarios using a block tester. Measurements of formation-breakdown pressure and fracture-propagation pressure were made with different cement-slurry compositions and compared with pressures obtained with drilling muds.
In an analysis of 40 well sections that reported losses before or during primary cementing operations, the rate and severity of lost circulation varied for the wells studied, but it was concluded that losses were commonly induced while running casing or during precement-job mud circulation, but rarely during cement placement.
The laboratory research confirmed the field observation: It would take much more pressure to open or reopen an existing fracture with cement slurry than with a synthetic-oil-based mud.
This paper will present findings from the field analysis and laboratory research. It will also discuss strategies to prepare the wellbore for preventing losses before the cementing operation and to optimize cement formulations if losses have been induced during drilling, casing running, or prejob mud circulation.