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Gorski, Dmitri (Heavelock AS) | Kvernland, Martin (Heavelock AS) | Borgen, Harald (Techni AS) | Godhavn, John-Morten (Equinor ASA) | Aamo, Ole Morten (NTNU – Norwegian University of Science and Technology) | Sangesland, Sigbjørn (NTNU – Norwegian University of Science and Technology)
Harsh weather conditions result in severe heave motion on floating drilling rigs. The drill string is heave-compensated during drilling ahead, however, when slips are set during drill pipe connections, the topside heave compensation system is disabled, and the drill string is then moving up and down together with the rig. Pressure oscillations below and around the drill bit, induced by such movement, are known as "surge & swab". These oscillations can be in the order of 20 bar or more during drill pipe connections in the North Sea and pose a serious challenge to drilling of wells with narrow pressure margins from floating rigs in harsh weather environment. A managed pressure drilling (MPD) choke at the surface cannot be used to control rig heave-induced surge & swab due to the fast nature of the pressure oscillations in question, stochastic character of the sea waves that cause them and long time-delay between topside choking and bottomhole response. Continuous Circulation System (CCS) might be able to reduce the pressure oscillations somewhat by maintaining constant mud flow during connections.
Computer simulations and laboratory experiments were previously used to investigate a novel method for attenuating surge & swab by utilizing an autonomous choke to be installed in the bottom-hole assembly (BHA). The bottomhole pressure oscillations can be effectively reduced through dynamic in-situ control of the mud flow through BHA by a downhole choke. This paper presents the downhole choke system and the results from the first pilot trial conducted in a mud flow loop at Ullrigg test rig in Stavanger utilizing a full-scale version of the choke. The prototype was subjected to drilling mud with flow rates up to 2500 lpm and differential pressure up to 250 bar to investigate its ability to accurately control the flow while at the same time withstanding the demanding conditions.
Satisfactory choke valve characteristics were obtained, indicating ability to control the flow with sufficient precision. Flow testing resulted in severe erosion of carbon steel components while wolfram carbide components were able to withstand the erosive nature of the flow. The test also uncovered challenges related to operation of the choke with high differential pressure and flow rates which could later be related to the motor, used to control the downhole choke assembly.
The next phase of the project is to design a downhole prototype and test it in an onshore test well to achieve Technology Readyness Level (TRL) 4 qualification ("ready for first use offshore"). The final goal is to qualify the downhole choke together with MPD and a Continuous Circulation System (CCS) for use on floating drilling rigs in harsh weather environment.
Rolfsvåg, Trond Arne (Hydrophilic AS) | Lindsay, Craig (Core Specialist Services Ltd) | Zuta, John (NORCE Norwegian Research Centre AS) | Vatne, Kåre Olav (NORCE Norwegian Research Centre AS) | Lohne, Arild (NORCE Norwegian Research Centre AS) | Iversen, Jan Erik (NORCE Norwegian Research Centre AS) | Guo, Ying (NORCE Norwegian Research Centre AS) | Askarinezhad, Reza (NORCE Norwegian Research Centre AS) | Undheim, Eirik (Aarbakke Innovation AS) | Gudmestad, Tarald (Aarbakke Innovation AS) | Bye, Arnulf (Aarbakke Innovation AS)
This paper documents that it is possible to measure the pressure of water inside a hydrocarbon reservoir. The pressure difference between oil and water could provide valuable information about the hydrocarbon column height of a new discovery. Detecting changes in the hydrocarbon – water pressure difference could work as an early warning system for water approaching a field in production. Knowledge about the hydrocarbon column height could speed up the appraisal process, or guide infill drilling, saving time and money. The environmental impact will be reduced because fewer wells will have to be drilled.
In most hydrocarbon reservoirs the water phase is likely to be continuous even at a very low water saturation and at a significant hydrocarbon overpressure. This is because of the polar nature of the water molecule and the polarity in the surface of the minerals in the reservoir: Water sticks to the surface of the reservoir grains. Given enough time the pressure gradient through this thin film of water becomes the same as if the water was in bulk. By measuring both the water and the hydrocarbon pressure at a given depth inside a hydrocarbon reservoir it is possible to estimate the vertical distance down to the free-water level. The only additional information needed are the densities of the fluids.
The water has lower pressure and lower mobility than the hydrocarbon phase, therefore specialized equipment will be needed to capture the water pressure. The pressure measuring probe must have a hydrophilic filter to prevent invasion of the hydrocarbon phase.
The pressure measurement of the thin water film should be made in an undisturbed part of the reservoir, i.e. it normally cannot be made at the wall of a well. A hole through the wall of the well and a short distance into the reservoir should be made for the probe to secure a representative water pressure measurement.
The Troll field is in the Norwegian sector of North Sea at water depth 300 – 350 m. The field came on stream in 1995 and developed as subsea field. The field has been Norway's biggest oil producer the past five years. The shut-in wellhead pressure is around 140 bar and static temperature 70°C.
The 6 5/8’’ × 5 ½’’ screens were run in 8 ½ horizontal reservoir section in one run to target depth at 6345 m. The length of screen section was 4300 m. The success of this job is considered as the longest screen run in the company because of excellent teamwork between onshore engineering and offshore teams.
To date, all the wells on Troll field over target depth approx. 6200 m were completed with minimum two screen runs which involves extra tubular management, need for service company personnel & equipment for two screen runs.
The planning of this operation required a thorough design of the landing string to run the screens. This included checking previous experiences on the same rig and field to carefully analyze the torque and drag simulations to understand the buckling & weight limitations. It was crucial to use correct friction factor in the simulations and quality control the input parameters which can impact the available weight & buckling. In addition, the downhole data from tripping out of hole with 8 ½’’ drilling BHA prior to run the screens was also utilized to understand the well condition.
Conventional well interventions using drill pipes, coiled tubing, and slickline suffer much from inaccuracy, absence of downhole control, and lack of surface monitoring. The oil and gas industry has been pushing for a better, lighter, and more innovative approach. During the last 25 years, emerging downhole electric and electrohydraulic tools deployed on electric line (e-line) have gradually replaced some conventional methods, enabling more efficient and precise operational execution with the help of surface read-out data and real-time monitoring while controlling the downhole tools via commands sent through the e-line, adjusting to the needs transmitted by sensors integrated in the tools themselves. The results have been well received, and precision has become a necessity in certain well interventions, especially where the life of a well is expected to extend and the recovery to become more sustainable. Consequently, precision interventions save considerable time and cost to the operators while offering safer alternatives to other methods.
In this case, we show how two cutting-edge, e-line technologies have solved two important challenges for an operator: (1) Orienting an e-line puncher tool sideways to secure circulation when punching tubing at high deviation, and (2) cutting tubing in compression without damaging the outer casing, leaving a clean, beveled edge for subsequent runs.
Both solutions were made available and executed flawlessly for the operator. Surface read-out data from both tools helped real-time monitoring and successful execution. This case demonstrates, once again, what a combination of e-line intervention and disruptive innovation can currently achieve for operators.
On a subsequent well, both solutions described above were combined in one run, saving further rig time and cost, and resulting in safer operations than alternative, conventional methods.
Bila, Alberto (Department of Geoscience and Petroleum, Norwegian University of Science and Technology) | Stensen, Jan Åge (SINTEF Industry and Department of Geoscience and Petroleum, Norwegian University of Science and Technology) | Torsæter, Ole (Norwegian University of Science and Technology)
Lack of relevant screening methods of oil recovery techniques for water flood with added nanoparticles in a given reservoir are hindering its implementation for enhanced oil recovery (EOR) purposes. Moreover, the understanding of the underlying mechanisms of oil increased by nanoparticles must be improved.
In this work, we screened twenty-three different types of silica nanoparticles as additives to injection water for oil recovery applications. The nanoparticles were surface functionalised to remain stable in the injection water and be active at the surface. The hypothesis is that the particles will improve the microscopic oil recovery efficiency of water flood in an oil reservoir. The concentrated solution of nanoparticles were prepared to 0.1 wt % concentration in synthetic North Sea water. Crude oil was obtained from a field in the North Sea. The following investigations were carried out to quickly verify the performance of nanoparticle oil recovery: 1) secondary injection through a visual glass micromodel. 2) For the prominent silica nanoparticles, we evaluated oil recovery by conducting secondary core flooding experiments in water-wet Berea sandstone rocks; and 3) the displacement mechanisms of nanoparticles were investigated by interfacial tension measurements between nanofluids and crude oil; Amott-wettability test; and by analyzing differential pressure across the core.
Experimental results from secondary floods showed that modified silica nanoparticles can boost oil recovery. The core flood recoveries ranged from 45.7% to 54.5% of original oil in place (OOIP) compared to 39.7% of reference water flood. Displacement studies revealed that, oil recovery was obtained from a contribution of interfacial tension reduction, wettability alteration, and log jamming effect due to pore blockage. This work suggests a procedure for screening nanoparticles for EOR applications while providing insights into the role of the modified-silica nanoparticles for recovery of oil.
When preparing a field development plan, the forecast value of the development can be sensitive to the order in which the wells are drilled. Determining the optimal drilling sequence generally requires many simulation runs. In this paper, we formulate the sequential decision problem of drilling schedule as one of finding a path in a decision tree that is most likely to generate the highest net-present-value (NPV). A non-parametric online learning methodology is developed to efficiently compute the sequence of drilling wells that is optimal or near optimal. The main ideas behind the approach are that heuristics from relaxed problems can be used to estimate the maximum value of complete drilling sequences constrained to previous wells, and that multiple online learning techniques can be used to improve the accuracy of the estimated values. The performance of various heuristic methods is studied in a model for which uncertainty in properties is neglected. The initial heuristic utilized in this work generates a higher estimated NPV than the actual maximum NPV. Although such a heuristic is guaranteed to find the true optimal drilling order when used in A* search, the cost of the search can be prohibitive unless the initial heuristic is highly accurate. For the variants of heuristic search methods with weighting parameters, the results show that it may not be possible to identify parameters that can be used to find a solution quickly without sacrificing the accuracy of the estimated NPV in this drilling sequence problem. In contrast, the online learned heuristics based on the observations from previous drilling steps are demonstrated to outperform the other variants of heuristic methods in terms of running time, accuracy of the estimated value and solution quality. Multi-learned heuristic search with space reduction is an efficient and fast method to find a solution with high value. Continuing the search with space restoration is guaranteed to improve the solution quality or find the same solution as the multi-learned heuristic search without any space reduction.
In a typical well completion system, retrievable plugs run on wireline are used to set production packers and thereafter, to perform leak testing of the upper completion tubing. There are significant costs and risks associated with these intervention operations to set and retrieve aforementioned plugs. This paper presents the development and implementation of a system using dissolvable technology that allows for interventionless packer-setting and tubing testing of upper completions. The solution developed is a packer-setting kit consisting of a seat profile and a dissolvable ball. The seat is run as part of the tubing string below the production packer. After landing the completion string, the dissolvable ball is dropped from surface to land on the seat profile below the packer. This ball-seat system holds pressure from above, thereby, enabling the production packer to be set and a leak testing of the tubing to be performed. Eventually, the ball dissolves completely in the presence of downhole packer fluids permitting start-up of production activities.
This paper documents the extensive qualification test program which was undertaken to qualify a dissolvable ball-seat system for one-such application. These tests were aimed to verify the capability of the packer-setting kit to fulfil the operational requirements (pressure rating, dissolution time periods) under the specific downhole conditions (packer fluid type, temperature). Following successful qualification testing, this solution was successfully implemented in 3 wells on the Norwegian Continental Shelf in 2018. Adopting this technology significantly improved operational efficiency by reducing well completion and intervention times along with associated costs. Consequently, this enabled earlier production start-up on these wells. The most challenging aspect of this new approach is the selection and qualification of a suitable dissolvable ball material appropriate for the application-specific requirements and operational constraints. The various steps and tests necessary to verify suitability of dissolvable technology for such applications are outlined in this work. Key operational considerations which need to be kept in mind when implementing this solution shall also be addressed.
The lateral movement of drill-pipes, while rotating, can be the source of diverse drilling problems, such as tool-joint wear, grinding of cuttings into a fine powder that is very hard to transport, formation instabilities. Yet, it is virtually impossible to estimate the sideway displacements of drill-pipes as soon as the distance is greater than a couple of stands from a measurement source, like a dynamic sub placed in the bottom hole assembly (BHA).
It is therefore tempting to place dynamic subs along the drill-string with the objective of detecting any pipe movements that could have a negative impact on the drilling operation. However, to be useful, the measurements must be made at a relatively high frequency, in practice above 80Hz, and with enough precision. For that reason, we have placed a dynamic sub that measures axial and tangential accelerations, rotational velocity, 2-axis bending moment, torque and tension, approximatively 300m behind the bit while drilling two 9 ½-in lateral sections of a horizontal multilateral well.
The dynamic sub sent rotational speed, torque and tension at 80Hz through wired-pipe telemetry and burst data for all the measurement channels were recorded in memory, for 10s at 800Hz every 15 minutes. We have been able to test a method to collect and interpret the high-speed telemetry data, i.e. 80Hz, and we have post-analyzed the burst memory data. A methodology has been developed to compensate systematic errors on the accelerometer sensors by taking advantage of the redundancy of the measurements present in the mechanical-sub. An interpretation software has been used to reconstruct the likely 3-dimensional pipe movement at the location of the measurement tool. The analysis has shown a surprisingly large variation of pipe movement patterns and astonishing fast changing levels of lateral movement throughout the two runs where the tool has been used.
With such a pipe reconstruction methodology at hand, it can be envisaged to perform the processing downhole, i.e. directly into the dynamic sub, and to transmit information about the 3-dimensional movement of the pipe. Such information would be valuable, when received in real-time from distributed sensors, to inform the drilling operational team about possible detrimental drill-pipe vibrations that are not necessarily associated with abnormally high accelerations.
The push within the oil and gas industry towards digitalization hold great promises for optimizing operations and improving efficiency. Therefore, most oil and gas companies have large initiatives within digitalization – huge efforts on data acquisition, Industrial Internet of Things, Artificial Intelligence (AI), Machine Learning (ML) etc. – all digital opportunities introduced to the industry in recent years. We look at data and models as oil and gas "assets" – much like physical assets used in operations (wells, platforms, compressors etc.). Thus, there is a perceived inherent value in data for operations.
For effective operations, the interesting part of data, models and digital capabilities, is the feedback loop it allows to the physical asset itself. One wants to close/open a valve for optimal production, ensure maintenance on machinery and ensure safe scaffolding operations without sending people offshore during planning. There are two types of feedback opportunities to the physical asset – either through automation or by humans. Both humans and automation algorithms can get advice from some "co-bot" based on AI, ML or other digital opportunities. When the feedback is given automatically, we have full control over the work performed by the algorithm or cobot, while the same is not the case when humans are involved.
At certain level engineers and operators know how to do the work – this is embedded into known "work processes." However, the actual interpretation of a work processes into concrete activities may lead to different tasks for team members – even for the same work. This gives lack of repeatability, inconsistency in operations, and makes effective collaborations challenging. In many ways, we lack (real time) data on the work itself, when it's done by humans.
This paper addresses this issue – we explain why data on the work and how effectively it is performed should be regarded as an asset in a similar way to real-time data and reservoir models. We show technologies and examples allowing organization to assess data on the work itself. We discuss how teams can work differently, and how technology can be used to drive consistency and KPIs toward more effective operations.
Reservoir stress path is most often used to couple the pore pressure change in a reservoir to the resulting change in the minimum horizontal stress in the reservoir. This stress path can directly be measured in a reservoir. The pore pressure is typically measured using standard equipment for doing so during drilling of wells. These pressure measurement devices are either run on wireline or in logging while drilling (LWD) tools. The minimum horizontal stress is typically measured in a hydraulic fracturing operation designed for this purpose. This operation can be performed under a casing shoe (often referred to as an extended leak-off test), through perforations (often referred to as a mini-frac test) or between two packer elements (referred to as a micro-frac test). The stress path will impact many geomechanical aspects in a field development, like wellbore stability, lost circulation (fracture gradient change) and solids production to name three. In the literature there are limited datasets on stress-paths during depletion, and even less on re-pressurization resulting from injection. The Valhall dataset is unique in the industry since it contains hundreds of tests from three different chalk formations. The data has been gathered from mini-frac tests as part of hydraulic propped fracturing stimulation jobs over a 36-year period, and is from an oil and gas industry perspective of very high quality. Water injection has been ongoing in the Tor reservoir the last 13 years and large amounts of data can be used to measure the stress path during re-pressurization. The Valhall data indicate one stress path for depletion and a slightly different stress path during re-pressurization. We compare the measured stress paths with predictions based on core measurements and numerical models and discuss the impact of pore collapse, fault reactivation, arching, and processes during re-pressurization