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.
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.
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.
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.
Unintentional collision between two wellbores may have serious economic and health, safety, and environmental consequences. It is therefore important to evaluate the probability of such an event in the well-planning phase and at critical stages during the drilling phase.
A commonly used approach is to analyze the collision probability between two points, one in each wellbore, which are determined from geometric criteria only. This procedure may ignore point pairs with higher collision probabilities, and thereby lead to overoptimistic conclusions. Typically, the results from such methods will be accurate only for simple wellbore geometries, such as straight sections, and for position uncertainties that are highly symmetrical with respect to the wellbores. More advanced methods that overcome such limitations are impractical for general application because of high conceptual or computational complexity.
This paper proposes novel analytic methods that may potentially overcome these problems. Formulae are derived for two important situations: the direct-hit (DH) and the unintentional-crossing (UC) scenarios. In both cases, the spatial region of interest is divided into carefully designed segments, such that the collision probability can be accurately evaluated for each segment. The total collision probability is then found by summing the results over all segments. The main advantage of this approach is that it gives accurate results for arbitrary well geometries and uncertainty-ellipsoid orientations.
The algorithms can easily be integrated in existing software for wellbore-anticollision analysis. The paper shows examples of results that are all in good agreement with control calculations. Compared with existing methods, the proposed methods are therefore believed to represent an improvement to quantitative collision-probability analysis for both the wellbore-planning and the drilling phases.
Water injection into soft sand is a global industry challenge because of the complex problem of maintaining sustained water-injection rates into the desired reservoir. Drilling, cementing, and completion engineers are addressing each technical and operational aspect of water injectors, including cement isolation. Cement serves as a barrier during well construction through to post-abandonment. It contributes to ensuring that no out-of-zone water injection occurs because of flow behind casing. If water does go out of zone, new drilling hazards that are a result of water breaching and a loss of reservoir management will occur.
At present, as far as we know, the industry does not have a systematic methodology for defining and verifying the required physical and mechanical properties of the cement to endure water-injection service and to retain its isolation capability during well life. Cement-integrity simulators (CISs) provide different answers, mainly because they all assume a different initial stress-state in the cement after hydration. As a consequence, a new CIS model that computes this stress state has been developed, along with a large-scale testing setup to validate its predictions.
The new model incorporates key-design parameters of effective CIS models: (1) The initial stress state after cement hydration is computed; (2) varying loadings that the cement sheath is submitted to are simulated; (3) the elasticity, plasticity, and failure of materials are taken into account; (4) the simulations are fast enough to facilitate sensitivity analysis; and (5) the model outputs allow the visualization of cement integrity across the entire length of the cement sheath, adjacent to reservoirs and to seals.
Parallel to the modeling work, a large-scale test apparatus was built to evaluate cement zonal isolation under water-injection pressure and temperature conditions. Its objective was to generate pressure and temperature cycles inside sections of cemented casing assemblies to replicate the conditions of pressure and temperature variations in a water-injection well.
The results of the test confirmed the accuracy of the new CIS model. They also showed that cooling because of water injection had a bigger impact on cement integrity than increasing pressure. In addition, the results showed that microannulus generation had more effect than tensile cracking in terms of cement-barrier-permeability increase.
Controlled annual mud level (CAML) is a managed-pressure drilling technology used to drill deep and ultradeep offshore wells that often encounter narrow and challenging operating windows. This technique uses a submersible pump to change the liquid level in the riser to control the bottomhole pressure (BHP) during drilling operations. The flexibility in changing the liquid level in the riser allows the use of higher-density drilling fluids, as well as higher pump rates.
In this paper, a sensitivity analysis is carried out to study the possibility of synergizing the CAML drilling technique and drilling-fluid performance to optimize the casing-design program. Drilling-fluid density, fluid rheological properties, sagging potential, lost circulation, and hole cleaning are the main investigated variables. The results show that, if sag-prevention properties and fluid rheological parameters are controlled, changing the liquid level in the riser and using higher-density drilling fluids will enable drilling deep, challenging offshore wells. In addition, the number of casing strings can be reduced with the proposed synergistic approach. A case study is performed in this paper for an offshore well in the Black Sea to validate this approach. The validation reveals that, if the synergistic approach is applied, the number of casing strings is reduced by approximately 26% in comparison to a conventional casing design. The paper also proposes a best-practice guideline of how to synergize the CAML drilling technique and drilling-fluid performance to optimize the casing-design program.
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 c-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.
Kuang, Yuchun (Southwest Petroleum University, China) | Luo, Jinwu (Southwest Petroleum University, China) | Wang, Fang (Southwest Petroleum University, China) | Yang, Yingxin (Southwest Petroleum University, China) | Li, Shu (Sichuan Deep and Fast Oil Drilling Tools Company Limited) | Zhang, Liang (Sichuan Deep and Fast Oil Drilling Tools Company Limited)
The powdery or laminar cuttings that are produced by a conventional polycrystalline-diamond-compact (PDC) bit are not suitable for geological logging. To solve this problem, this paper introduces a new PDC bit with suction-type minicore drills. The basic working principle of this new PDC bit is to remove the main cutters in the center of the PDC bit. The new PDC bit can generate minicores of formations with a certain diameter and break these cores in a timely manner during drilling. By use of a special hydraulic design, the broken minicores are sucked from the bottom of the well through the internal coring channel of the bit.
Combined with the theory of rock-breaking simulation and solid/liquid two-phase flow, the effects of different jet-nozzle diameters (6, 8, and 10 mm) on the suction in the coring channel were investigated by considering the quality of the minicores, cuttings, and drilling fluid. The numerical-simulation data show that the cores, cuttings, and drilling fluid that are discharged from the discharge hole have the highest quality if a jet nozzle with a diameter of 8 mm is used. In other words, the suction force generated from the negative-pressure cavity is stronger than that generated with the other two jet-nozzle sizes (6 and 10 mm) investigated.
A test bit was subjected to laboratory and field tests to verify the coring. The experimental results show that the collected cores are generally columnar, and both the integrity and the collection rate of the core are high.
This study demonstrates the feasibility of the concept of the new PDC bit with suction-type minicore drills and provides a design scheme to reduce the coring cost and improve the quality of geological logging.
This work presents a new multivariable controller for management of topside and bottomhole objectives during underbalanced drilling (UBD). A model predictive control (MPC) solution is used to control pressures, rate of penetration (ROP), and flow downhole while also ensuring that the topside processing constraints are respected.
With automated control, it is possible to reduce nonproductive time (NPT), improve safety, and operate closer to the process constraints. MPC is a good fit for UBD because of its easy inherent handling of multiple objectives and constraints. With good pressure control, it is in some cases also possible to reduce the number of casing strings.
The control solution is evaluated through simulations in a high-fidelity multiphase-flow oil and gas simulator (OLGA). It is shown that we can meet multiple objectives both at the surface and at different locations in the well. The optimization problem is solved with good results well within the given time constraints.
The used linear prediction models are relatively easy to understand and maintain. They are also fast and well-suited for optimization and predictions. However, the process is nonlinear, and the linear models will be less accurate as the process conditions change. Retuning or model adaptation might be required to obtain the desired performance. It is possible to include nonlinear models in the control framework, referred to as nonlinear MPC (NMPC), but this will add complexity and require more computational power.