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.
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.
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.
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.
Wellbore tortuosity or spiraling can lead to the trapping of a cuttings bed in a trough of a tortuous hole, thereby leading to poor hole cleaning in extended-reach drilling. The objectives of this study included quantitatively evaluating the influences of wellbore tortuosity on hole cleaning and cuttings-transport behavior in extended-reach drilling. In addition, the study provided a recommendation of effective drilling practices. The study involved performing hole-cleaning-optimization studies for an extended-reach well with a long horizontal section aiming for maximum reservoir contact, by use of a transient cuttings-transport simulator. The planned trajectory of the well was assumed to have a certain degree of wellbore tortuosity in the horizontal section. The pump rate and bottoms-up circulation operation were optimized on the basis of parameter studies and additional transient simulations by considering the effects of penetration rate and variation in cuttings size.
Simulation results indicated the formation of a considerably high cuttings bed, particularly in the downdip intervals (updip in mudflow direction) at an insufficient pump rate; one-third to one-half of the drillpipe diameter could be potentially buried in a cuttings-deposit bed, and this can result in a packed-off hole or stuck pipe. A higher rate of penetration (ROP) can also cause insufficient hole cleaning. In this case, controlled drilling that maintains a reasonably low penetration rate may be effective. Furthermore, borehole breakout may enlarge hole diameter and generate large-sized cuttings. Both of these can have negative impacts on hole cleaning, and, thus, borehole stability and smooth wellbore-trajectory controls should be carefully considered. To clean these holes, frequent bottoms-up circulations were effective at each stand of drilling even if the optimization of other drilling parameters was limited. The findings also revealed that accumulated cuttings in a tortuous wellbore were trapped in the trough of the hole, and that the bed height of locally trapped cuttings in the downdip intervals could be much higher than that indicated by previous studies.
Design of drilling fluids, spacers, cement slurries, and fracturing fluids is often done by trial and error in the laboratory. In the first step, the required properties of these fluids are categorized and then efforts will be started with a rough idea of the optimal composition. This first guess usually depends on the experience of the laboratory analyst or fluid engineer. Afterward, the trial-and-error testing starts, and it continues until the fluid design moves closer to the desired fluid criteria. There are several test data that would not be used in this method, and it is difficult to digest a large amount of information by the user. Trial and error could be time-consuming, very costly, and misleading. Today, there is a need for an intelligent system that uses all the available data (big data), even if the data sets are not close to the desired goal, and offers insights for fluid designs.
This paper conducted a study on the application of machine-learning-based methodologies, including Gaussian-process regression (GPR) and artificial neural networks (ANNs), to reduce the costs of testing, integrate available experimental data, and eliminate the need for personnel supervision. These practical nonlinear-regression methods empower efficient and fast prediction tools that do not require including complex physics of the underlying system while integrating all available data from different sources. GPR, which is also known as Kriging in geostatistics literature, has exceptional advantages over traditional regression methods because it does not require a known form for regression function and also has the capability of determining the estimation error and the confidence interval. This machine-learning-based tool offers insights for intelligent fluid design and could reduce costs.
Estimates of formation pore pressure before and while drilling are important inputs for well planning and operational decision making.
A method is proposed to determine pore pressure from a combination of downhole drilling-mechanics parameters and in-situ rock data with the concept of mechanical specific energy (MSE) and drilling efficiency (DE). This pore-pressure estimation method (termed DEMSE) is based on the theory that energy spent at the bit to remove a volume of rock is a function of in-situ rock strength and the differential pressure that the rock is subjected to during drilling.
A work flow is provided that illustrates the steps required to estimate pore pressure from drilling parameters and rock-mechanics data by use of the DEMSE method. Pore pressure estimated from the DEMSE method is compared with pore-pressure estimates derived through a conventional sonic log that is based on empirical technique for a deepwater well in the Gulf of Mexico (GOM). Pore-pressure estimates from the DEMSE method generally agree in magnitude and trend with the pore-pressure estimates derived from sonic-log data. The results of the DEMSE method have also been compared with pore-pressure estimates from the classical d-exponent (dXc) approach to highlight the advantages of DEMSE over traditional dXc methods.
Finally, the importance of using downhole vs. surface data for pore-pressure estimation purposes, specifically torque measurements at the bit, is illustrated through a field example. These findings suggest that downhole drilling-mechanics data, when properly used, can provide reliable independent estimates of pore pressure in real time at the bit and can be used for post-well-analysis to assist with constructing pore-pressure forecasts.
Yang, Ruiyue (China University of Petroleum, Beijing) | Huang, Zhongwei (China University of Petroleum, Beijing) | Li, Gensheng (China University of Petroleum, Beijing) | Sepehrnoori, Kamy (University of Texas at Austin) | Lin, Qing (China University of Petroleum, Beijing) | Cai, Chengzheng (China University of Mining and Technology)
Steel slotted liners are often used in horizontal coalbed-methane (CBM) well completions. However, the disadvantages associated with these liners, such as high operation costs, corrosion susceptibility, and safety considerations in subsequent mining processes, can limit their performance. One possible alternative is a plastic slotted liner. A major challenge for designing a plastic slotted liner is providing sufficient structural integrity without creating a significant restriction for gas that flows into a wellbore.
In this paper, we present an optimization design for polyvinyl chloride (PVC) slotted liners. Our design couples the influence of the mechanical integrity of the liner and the inflow performance. The optimization parameters are the slot geometrical parameters. The boundary conditions are identified by the failure criteria and the influence of various slot-parameter adjustments through laboratory compression experiments. Two models--a collapse-bearing-capacity model and a skin-factor model (Furui et al. 2005)--are used to optimize the design of the PVC slotted liners. A genetic algorithm is used to maximize the collapse-bearing capacity and minimize the skin factor. Finally, a selection guide for the optimal combination of slot parameters is provided.
The key findings of this work are beneficial for determining the design criteria of plastic slotted liners in horizontal CBM wells. In addition, the proposed “cross-disciplinary” evaluation method is expected to provide a valuable optimization approach for slotted-liner completions.