While automation is already a big deal for the drilling part of a well construction, tubular running services like casing and tubing installation has been more or less neglected in this process. Reasons for that are that special equipment is required for tubular makeup which is usually brought to the rig only for one particular task. Integration is often difficult since no industry standard exists for this operation. Furthermore this equipment has become difficult to use requiring special training of the operators.
The tubular running process comprises the use of a tong to makeup and break out connections. Over the years many different tong types have been developed, from manual tongs to fully mechanized power tongs. All tongs comprise a torque/turn measuring system which needs to be installed on site. Adjustments need to be made in order to reflect the setup e.g. tong type, load cell range, turns counter resolution, etc. Mechanized tongs require even more equipment to be brought to the rig floor and connected to the tong. All that leads to longer rig up time, more floor space necessary on the rig floor, more personnel and potential sources of failure. The evaluation of the connection bears another risk. So far a human looked at the torque/turns graph and evaluated the connection. This required a certain resolution of the screen and a good understanding of the connection requirements.
A new system has been developed to address the challenges described above. The new generation of tongs is equipped with computers and additional sensors. The tongs do not require any additional equipment to be connected to it. The interfaces are reduced to the minimum, using industry standards like Ethernet, Wi-Fi and Bluetooth. The makeup is now controlled by the system eliminating any operator-specific influences or other human factors and at the same time, simplifying the use of the equipment. Algorithms programmed according to pipe OEM specifications now evaluate the connection which eliminates subjective graphical interpretations.
This paper highlights the challenges of tubular running services and how this process can be automated in order to increase connection quality and reduce costs.
Rognmo, A. U. (University of Bergen) | Al-Khayyat, N. (University of Bergen) | Heldal, S. (University of Bergen) | Vikingstad, I. (University of Bergen) | Eide, O. (University of Bergen) | Fredriksen, S. B. (University of Bergen) | Alcorn, Z. P. (University of Bergen) | Graue, A. (University of Bergen) | Bryant, S. L. (University of Calgary) | Kovscek, A. R. (Stanford University) | Ferno, M. A. (University of Bergen)
We show experimentally that surface treated silica nanoparticles greatly enhance the thermodynamic stability of CO2-foam compared to other foam stabilizers at elevated temperatures and salinities in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2-foam for enhanced oil recovery by improved sweep efficiency, resulting in reduced carbon footprint from oil production. Our results show that surface modified nanoparticles are able to stabilize CO2-foam at elevated temperatures and extreme brine salinities, and demonstrate that nanoparticle injection for improved CO2-foam mobility is an upcoming CCUS technology for mature fields. New experimental results show that 1) nanofluids remain stable at extreme salinities (up to 25 wt% TDS) with the presence of both monovalent and divalent ions; 2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 - 4 times higher with nanoparticles compared to no foaming agent; 3) CO2 stored during CCUS with nanoparticle stabilized CO2-foam increased by over 300% compared to co-injections without nanoparticles.
Naturally fractured reservoirs with low permeability and mixed-wet properties usually have poor waterflood performance because the imbibition of water into matrix is not very significant. Surfactants could be used to change matrix wettability to more water-wet and thereby improving the imbibition of water into matrix. Surfactants can also decrease water/oil interfacial tension (IFT) resulting in mobilization of residual oil. The goal of this study is to analyze the wettability alteration and IFT decrease in the imbibition process in fractured reservoirs by simulating surfactant imbibition at core scale.
The simulator Eclipse is used to simulate wettability alteration and IFT decrease separately or simultaneously. A 3D model is set up to model a core surrounded by water/surfactant solution in a container with an injector and a producer. The injection and production rates are 0.01 cm3/hr, therefore, the viscous force can be ignored. Three different kinds of surfactant with different properties are used. Two of them have only one mechanism each, either wettability alteration or IFT decrease, and the other has both mechanisms.
In the simulation study of the injection of the surfactant that only changes the wettability to more waterwet, the ultimate oil recovery is larger and oil recovery rate is bigger than for the case with no surfactant injection. The simulation study with the surfactant that only reduces the IFT shows that ultimate oil recovery is increased when the IFT at critical micelle concentration (CMC), which is expressed as IFTCMC, is lower than 0.05 mN/m. However, at the beginning of the imbibition, the lower IFT leads to a lower recovery rate. The study of the surfactant that has both mechanisms shows that there exist optimal IFTCMC's at different wettability conditions. If the matrix is rendered strongly water-wet by surfactant, the optimal IFTCMC is 19 mN/m. If the surfactant has a weak capability of wettability alteration (the matrix is still mixed-wet), the IFTCMC needs to be reduced to ultralow value. The present studies show that wettability alteration is a more important parameter for the surfactant imbibition in fractured reservoirs than changes in IFT.
This work improves the understanding of the interplay between the main mechanisms of surfactant enhanced oil recovery (EOR) from fractured reservoirs, and provides a reference for the surfactant screening for improving oil recovery in naturally fractured mixed-wet or oil-wet reservoirs.
Beeh, Hany Ahmed (Schlumberger) | Nobre, Daniel (Schlumberger) | Ba, Samba (Schlumberger) | Yan, Xiaolu (Schlumberger) | Lauritsen, Åshild (Statoil) | Døssland, Ørjan (Statoil) | Hodne, Jarleif (Statoil)
The challenging environment in the Kvitebjørn field offshore Norway comprises high-temperature wells, long drilling hours, low rate of penetration (ROP), managed pressure drilling (MPD), and mud additive requirements, all of which are very detrimental for operations and reliability of the positive displacement motor (PDM) power section. In fact, until now, no one has successfully drilled the 5 ¾-in. section in a single run due primarily to motor failures such as elastomer chunking and debonding.
This paper presents the steps used for optimizing the selection of a PDM section to achieve a single-run drilling operation with improved ROP. The method includes understanding the drilling environment, type of wells, rig capabilities, formations, temperatures, MPD, and drilling fluid requirements. Furthermore, the usual motor and bottomhole assembly requirements must be evaluated and the mud compatibility with the elastomer must be scrutinized. All of these variables were then input into a modeling engineering workflow to simulate and analyze the power output, the elastomer fatigue life, the hysteresis heating, and the debonding stress to select the best possible PDM candidate for the drilling job.
A new long-life elastomer and the drilling parameters recommended by the mud motor modeling resulted in drilling this section in a single run for the first time in the field. Simultaneously, it was possible to drill to the deepest total depth without any need to set the section total depth shallower, as occurred in previous wells due to motor failures. The motor drilled through a very thick cemented sandstone stringer with no stall incidents. This motor set new records for drilling the 5 ¾-in. section with a total run length 60% longer than the previous longest run and a total pumping time 67% greater than the previous record.
The combined new technologies of the modeling and the new long-life elastomer were applied for the first time in the anticipated challenging drilling conditions. The successful results demonstrated that with thorough analysis and proper planning, one can achieve a step change in performance and reliability without additional costs. The scope of the operation is even broader than the mud motor application.
Ensemble-based methods are among the state-of-the-art history matching algorithms. In practice, they often suffer from ensemble collapse, a phenomenon that deteriorates history matching performance. To prevent ensemble collapse, it is customary to equip an ensemble history matching algorithm with a certain localization scheme. Conventional localization methods use distances between physical locations of model variables and observations to modify the degree of observations' influence on model updates. Distance- based localization methods work well in many problems, but they also suffer from some long-standing issues, including, for instance, the dependence on the presence of physical locations of both model variables and observations, the challenges in dealing with nonlocal and time-lapse observations, and the non-adaptivity to handle different types of model variables. To enhance the applicability of localization to various history matching problems, we propose to adopt an adaptive localization scheme that exploits the correlations between model variables and observations for localization. We elaborate how correlation-based adaptive localization can mitigate or overcome the noticed issues arising in conventional distance-based localization.
To demonstrate the efficacy of correlation-based adaptive localization, we apply it to history-match the real production data of the full Norne field model using an iterative ensemble smoother (iES), and compare the history matching results to those obtained by using the same iES but with distance-based localization. Our study indicates that, in comparison to distance-based localization, correlation- based localization not only achieves close or better performance in terms of data mismatch, but also is more convenient to implement and use in practical history matching problems. As a result, the proposed correlation-based localization scheme may serve as a viable alternative to conventional distance-based localization.
Measurement While Drilling (MWD) is a common survey tool used in wellbore positioning. The industry often uses the Industry Steering Committee on Wellbore Survey Accuracy (ISCWSA) error models for estimating the Wellbore Position Uncertainty (WPU). However, the model's sensitivity to direction and nature of trajectory has not been discussed in detail. In this paper, a software model has been developed to better understand the influence of the individual error sources on measurement and position uncertainty in various drilling directions and hole sections.
Most operators have classified accurate wellbore positioning and directional design as one of the pillars of safety. It is commonly known that measurement accuracy of frequently used MWD instruments decreases with increasing hole inclination. Survey accuracy is also influenced by North to East direction. This work provides a detailed understanding of the behavior and contribution of each survey error source and screens the error terms contributing most towards WPU. Visualizing the contribution of each error source as a function of well path direction and inclination will support the understanding of position uncertainty of individual wells.
The results in this paper are based on analysis of the ISCWSA Non-mag error model. It has been observed that some errors are most dominant in the North/South drilling direction while others are most dominant in the East/West direction. Similarly, some error sources are most effective in the vertical hole section and least effective in the build-up or horizontal sections. This process continues for all different error sources in various hole sections and drilling directions. Therefore, this paper has summarized the most important error sources for the vertical, build-up and horizontal sections of the three wells, i.e North/South (NS), North/East (NE) & East/West (EW). The visualization of error sources will provide a more focused approach towards ultimately reducing the WPU.
The work in this paper is a part of a new digital well planning and well construction software tool. The working title of this software is Life Cycle Well Integrity Model – LCWIM.
This case study aims to share the experience and improve the understanding of downhole shock and vibration and demonstrate how it can be prevented using thorough offset analysis, an advanced bit design, downhole mechanics module, and detailed drilling roadmap. The new approach delivered a step change in the performance of the 17 ½-in. section in Valemon field, in the Norwegian sector of the North Sea. Employing a one-run strategy through this extremely demanding section could eliminate the need for a dedicated motor run to withstand high shocks through the sandy interval with interbedded limestone and cemented sand layers. Using a point-the-bit bottomhole assembly (BHA) with a detailed drilling roadmap for every group of formations secured smooth drilling, pull out, and running of the intermediate 14-in. × 13 3/8 in. casing to provide integrity to drill 12 1/4-in. section.
An advanced bit design balanced drilling with low aggressiveness through sand without compromising the performance through the interbedded limestone stringers and claystone. The conical-shaped cutter placed behind the main PDC conventional cutters successfully controlled the depth of cut through the sandy intervals and mitigated the downhole shocks.
A detailed drilling roadmap was developed to define formation-specific drilling parameters to mitigate the shock-related failures on similar lithology.
A downhole drilling mechanics module was used to provide real-time axial, lateral, and torsional shock and vibration data, which enabled adjustment of surface drilling parameters accordingly.
Production at Heidrun is normally limited by the gas handling capacity. Maximum oil production is achieved by producing wells with the lowest gas/oil ratio (GOR) and at the same time utilize the available gas capacity. GOR may change over time, so to obtain desired production it is vital with a continuous follow-up work of well testing and maintenance of multiphase meters. The Heidrun field also has many wells with challenges like; sand entrainment, drifting draw-down, limited draw-down or bottom hole pressure (BHP) and drifting GOR. These elements are crucial to control to achieve desired production. This time-consuming task is handled through a close cooperation between offshore operations and production engineers onshore. Automatic choke control is installed at Heidrun to ensure operation at the maximum gas capacity and keeping the wells at desired operating point. The automatic controllers lead more precise production from each well with a totalized higher production, reduced emissions, reduced operator loads and is a valuable tool for production optimization.
In line with the increase in decommissioning/abandonment work in the North Sea, a major operator had the objective to permanently abandon a well that had been temporarily suspended. There were several key challenges associated with this project: high pore pressure and temperature, a completion packer set in a target abandonment interval, and small cement plug volumes. These obstacles had to be overcome to complete the abandonment safely and efficiently. The deeper barrier envelope was established by running flush slimline tubing through the 5-in. tubing and 9 7/8-in. production packer. The cement plug was then successfully placed below, across, and above the production packer. With this approach, only one cement plug was needed instead of the base plan of two, thus reducing rig time. The combined barrier cement plug was successfully tagged and inflow tested. This approach also eliminated the need to remove the production packer prior to the abandonment plug being set, which saved the operator a minimum 7 to 10 days of rig time. This paper outlines the detailed design preparations and presents the case history where these steps were implemented successfully.
The objective is to compare two different transient models for evaluating kick management in backpressure managed pressure drilling systems and to analyse numerical uncertainties and impact on simulation results.
Two different numerical methods will be compared with respect to how accurate they describe the maximum surface rates occurring during a kick scenario with water based mud. The importance of being aware of the uncertainty in results due to numerical diffusion is demonstrated. In addition, different techniques for reducing the numerical diffusion will be discussed and the impact on the predicted rates will be demonstrated. This will include a study of grid refinement and application of front tracking or slope limiter techniques. In addition, a comparison of a kick in oil based mud vs. water based mud in a HPHT MPD scenario will also be shown to highlight the main difference between these systems.
A backpressure managed pressure drilling system makes it possible to manage small pressure margins since bottomhole pressure can be controlled by choke pressure adjustments. However, when operating close to pore pressure, small kicks can be taken. These influxes can be circulated to surface if the surface equipment can handle the pressure and the mud gas separator have sufficient capacity. How large kicks one can handle is a decision that can be supported by transient simulations. Here it will be demonstrated that it is important to be aware of and reduce the numerical diffusion to improve prediction of the maximum rates that will occur. It will be shown that by increasing number of boxes in the discretization and introducing methods for reducing numerical diffusion, a more accurate prediction of the maximum rates occurring can be obtained.
The main contribution of this work will be to make engineers aware of that there can be uncertainties involved in the simulation tools they are using and to share knowledge about how one can reduce those uncertainties.