A traction tool has been built and tested as a part of the development of a long reach well concept. The application of the traction tool to assist the running of liners and sand screens in challenging wellbores is studied and the results and conclusions are described.
Full-scale testing of the traction unit prototype has demonstrated that it can deliver large axial forces to the string. A prototype tool for assisting during the completion phase of challenging wellbores is described, including the tool's measured performance from testing in casing.
The industry partners supporting the development work identified an opportunity to utilize the device to assist the completion operation to ensure that the target depth is reached.
Different scenarios where a traction device can provide a benefit include: Buckling of the running string in extended reach wells Insufficient available string weight in shallow reservoirs Avoid rotating sand screens to reduce axial friction
Buckling of the running string in extended reach wells
Insufficient available string weight in shallow reservoirs
Avoid rotating sand screens to reduce axial friction
The benefit of utilizing this tool is demonstrated by simulating the completion operation. Comparative well case studies are performed to study the completion operation, with and without the traction system included. A torque and drag model is used to estimate the mechanical forces present during the running of the completion string and these are compared to the buckling and load limits. Input parameters such as wellbore geometry, friction factors and completion string specifics are taken from relevant well examples. The operational performance for different positions of the tool in the running/completion string is also investigated.
Several theories exist for estimating permissible well drawdowns based on mechanical properties of the formation. These models are well developed and extensively used for the initiation of sand failure. However, models for predicting sand volumes and the sanding behavior post failure are plagued by difficulties in characterizing the mechanical properties of the failed/plastified area, the complicated interplay of erosion and production of sand on stress distribution in the near wellbore and from assumptions of idealized geometries. This work describes a method for determining optimum bean-up strategies that limit mobilization of material such as fines or sand from failed perforations/sand-face. The method nicely circumvents issues that can limit the applicability of theoretical models when optimizing well bean-up by simply ensuring that any transient pressure gradients that develop are lower than the pressure gradients that exist in near wellbore for the normal operating state of the well. The assumption is that the asset is operating the wells at flow rates/drawdown that are acceptable to them in terms of sanding/solids production. Such an approach can be used to minimize sand production during regular bean-ups for wells that are produced at ASR (Acceptable Sand Rates) and for wells where fines mobilization is suspected in causing time dependent skin effects and plugging. Different strategies are given to estimate the maximum step change increases in drawdown, the number of discrete steps and the total bean-up time. Furthermore, a method is presented showing how the pressure profile observed following a shut-in can be used to determine the optimum bean-up rate for any well - without knowing the exact details of the well and flow geometry or the different diffusivity coefficients and properties of the various producing layers. This is a new insight and can be a very powerful tool.
AbstractWhen permanently abandoning a well, each seal above a Distinct Permeable Zone (DPZ) needs to be restored with a cross-sectional barrier that will withstand the test of time. The Perforate, Wash and Cement (PWC) technology was developed as an alternative to section milling in situations where the wellbore barrier needs to be placed across a section of uncemented casing. Section milling is time consuming and results in exposing the BOP to swarf. The PWC method, on the other hand, is a more time-efficient process that consists of perforating the casing, washing the annulus behind it, and placing cement across the whole cross-section of the wellbore in a single run. However, some of the efficiency gain of the PWC method over section milling is lost when it comes to the barrier verification process. For section milled plugs, the verification process is usually the same as the one used for conventional wellbore cement plugs, since all the casing has been removed across the section milled window: the plug needs to be tagged/weight tested and pressure tested (except for section milled plugs where the top of the plug is left in open hole). On the other hand, as over 90% of the casing remains when installing a cross sectional barrier with PWC, the verification process typically involves two steps: 1) verify the annular component of the barrier, and 2) verify its internal one. In order to verify the annular part of the barrier, the internal barrier (cement plug) needs to be drilled out, and the annulus logged with a cement bond logging tool. A new internal cement plug then needs to be re-set and verified using the same verification method as for section milled plugs.During the first phase of the Valhall DP Plug & Abandonment (P&A) campaign, the PWC technique was used repeatedly to create primary and secondary barriers in the 9 5/8″ casing and 9 5/8″ casing × 12 1/4″ hole annulus, each time using the same design and execution parameters. After building a successful track record of PWC jobs in 9 5/8″ casing, a process was initiated to develop a non-destructive and more efficient alternative verification process, specific to PWC operations that would not require to systematically having to drill out the wellbore cement to log the annular barrier. The intention was to base this alternative verification method on a consistent track record, a strict design and operational parameter set (Qualification Matrix), and to include this alternative verification method in a proposed NORSOK Element Acceptance Criteria (EAC) Table specific to barriers installed using the PWC technique. This PWC EAC Table is intended to be used as a best practice for designing, executing and verifying PWC jobs, and is recommended for implementation into the next revision of the NORSOK D-010 Guideline.
AbstractA well was completed in April 2014 and put online a day after completion. However, it was shut-in shortly after due to a production trip. Massive sand production (2 000 pounds per thousand barrels) was observed during the restart of the well. Sand free production could not be achieved by performing multiple choke reductions. The sand shut-off intervention failed and distributed acoustic sensing indicated multiple sand entry points along the wellbore.A concentric coiled tubing (CCT) sand vacuuming operation was planned to be performed in order to clean out the well and reinstate production. A previously used conventional sand cyclone, and flowback system for CCT cleanout operations, needed to be replaced. This large unit had low separation efficiency resulting in excessive amounts of solids being transported to the process facilities. For a higher separation efficiency, this original unit was replaced by a compact (200cm x 200cm footprint) patented dual vessel desander, a passive design with no internal motor, and a stackable filter unit.The system was first put into operation during a CCT sand vacuuming intervention to reinstate the production from the well. The use of the system resulted in major cost savings due to the introduction of a less complex surface solids removal system, and majorly reduced footprint, giving a reduced rig up/rig down time and improved HSE. In addition, the system resulted in increased operational efficiency due to the 100% removal of solids from the flow stream.This paper describes a CCT sand cleanout operation where a dual vessel non-motorized desander, with a stackable filter unit, was used and discusses a case study presenting operational considerations, system description and results of the operation.
Pattarini, Giorgio (University of Stavanger) | Strømø, Kjartan Moe (Sunnhordaland Mekaniske Verksted AS) | Saasen, Arild (University of Stavanger) | Amundsen, Per Amund (University of Stavanger) | Pallin, Jan Egil (Sapeg AS Norway) | Hodne, Helge (University of Stavanger)
AbstractDrilling fluids contain magnetic contaminations that negatively affect Measurement While Drilling directional tools and causes damage to the equipment in contact with the fluid. The effect is relevant while drilling long deviated wells. Ditch magnets are routinely installed in the fluid system to remove magnetic particles while drilling, with the purpose of protecting the Shale Shaker screens from large metallic debris, serve as monitoring tool to detect troubles in the drilling operations and clean the fluid from magnetic particles.In this paper we describe field data for the operation and efficiency of the ditch magnets. An extensive set of samples of drilling fluid and of ditch magnets debris have been taken during offshore operations and have been brought onshore for detailed investigations. The material extracted has been assessed as constituted mainly by steel swarfs and steel fines.The magnetic materials still present in the used drilling fluid have been extracted and quantified by a novel method that provide higher extraction rates and better accuracy than the methods currently employed in the industry, allowing to assess the actual content of magnetic contaminant. The magnetic susceptibility of the fluid has been measured and compared with values predicted for a known concentration of magnetic contaminants, allowing for the evaluation of the bias induced by them on the magnetometers of the MWD tools employed.The capability of ditch magnets to remove the magnetic contaminants from fluid is quantified and compared with other available methods, like gravity separation, with special focus on the removal of magnetic particles in the range of few microns. Operational details and current issues in the deployment of ditch magnets are reviewed, and the most viable directions for improvement are briefly discussed.
AbstractAfter an extended plateau of manual operations, the industry is in a steep climb for performance and precision to reach modern manufacturing levels. This paper shows how we will handle risk management and experience transfer in digital drilling and well operations. Experience transfer and risk management are the two most crucial tasks in well planning, and the leap from manual to digital will enable wider and more comprehensive analysis in planning, and enormous cost savings in operations. Digital risk management and experience transfer is the key to continuously learning organizations.
AbstractInternational standards for well barrier integrity traditionally prescribe cement as annular sealing material. Despite a more than 100-year long history using cementing techniques, a high number of wells have poor annular integrity and are facing sustained casing pressure (SCP). A quality assessment of the cement seal is obtained by return volume and surface pressure trend calculations together with bond logs. All of these measurements are indirect and open for interpretation. Commonly, excess cement volumes are pumped to account for uncertainties but cement failure rate remains high.This paper describes an extensive testing and qualification program performed on a wireless downhole measurement system. Testing has been done on a component and system level basis on the permanently deployed equipment together with the hardware, software and telemetry on the equipment designed to retrieve the data. Focus has been given to robustness and simplicity to accurately capture the data of interest and ensure a fast and reliable download.A direct measurement of annular integrity is now available. A continuous pressure and temperature measurement, named the Well Data Monitor (WDM), can be mounted on the exterior of the casing or liner. The system is non-intrusive to the tubulars and communicates by acoustics through the pipe-wall. No control lines to surface are needed. Interrogation of the sensor pack will provide a full history of events from deployment to the time of download. Hence, historical pressure and temperature data are available from the time of deployment, through the process of establishment of annular barriers to the final verification test. The verification test will provide a direct and non-negotiable measurement of integrity.The development of the WDM was initiated following a need to provide verification for the Well Annular Barrier (WAB) to confirm to Norsok D-010 barrier requirements and to use the WAB as a barrier in open-hole.
AbstractToday's practice on the Norwegian Continental Shelf when designing solutions for permanent plug and abandonment (P&A) complies with NORSOK Standard D-010. This is a prescriptive approach to P&A, as opposed to a "fit for purpose" risk-based approach. A risk-based approach means that any given P&A solution is expressed in terms of the leakage risk, which can be formulated in terms of the following quantities; the probability that the (permanent) barrier system will fail in a given time period and the corresponding consequence in terms of leakage to the environment.As a part of building a leakage risk model for permanently plugged and abandoned wells, a simple leakage rate calculator has been developed for quick evaluation of the leakage potential from a given (permanent) well barrier solution. The leakage potential from the well can then be quantitatively assessed taking into account different leakage pathways including leakage through bulk cement, through cement cracks and through micro-annuli along cement interfaces.In the paper, we will provide models to estimate leakage rate for each leakage pathway and show how to integrate them in an overall leakage calculator, to obtain a description of leakage flow from the reservoir through failed barriers to the environment. The information and input parameters needed to achieve this will be discussed, and uncertain parameters will be treated probabilistically, thus allowing for expressing uncertainty in the leakage rate estimate.Results from the leakage calculator will be demonstrated on a synthetic case, showing variants of a permanently plugged and abandoned well.
AbstractThis work is focused on exploring the applicability of intelligent methods in assessing porosity and permeability in the context of reservoir characterization. The main motivation underlying our study is that appropriate estimation of reservoir petrophysical parameters such as porosity and/or permeability is a key step for in-situ hydrocarbon reservoir evaluation. We ground our analysis on information on log-depth, caliper, conductivity, sonic logging, natural gamma, density and neutron porosity, water saturation, percentage of shale volume, and type of lithology collected from well loggings in an oil field in the middle-east (a total number of 11 exploratory wells are considered). Data also include porosities and permeabilities evaluated on core samples from the same wells. All these data are embedded in a neural network-based approach which enables us to establish input-output relationships in terms of an optimized number of input variables. Three diverse intelligent techniques are tested. These include: (i) classical artificial neural networks; (ii) artificial neural networks based on principal component analysis (PCA) transformation; and (iii) statistical neural networks based on a bagging approach. Our results suggest that the statistical neural network is most effective for the field setting considered. The application of this neural network with 9 input parameters provides reliable performances in 94% and 81% of the cases, respectively in the training and validation phases, for the estimation of porosity. A trained network with 10 input parameters leads to successfull reproduction of permeability values in 85% and 79.5% of the cases, respectively during training and validation of the network. Results from this study are expected to be transferable to applications involving evaluation of petrophysical properties of a target reservoir in the presence of incomplete well log datasets.
AbstractA reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling fluid filtrate loss volumes. This paper will examine the factors which contributed to alterations in the core samples.A series of corefloods were carried out using core from 2 formations and different drilling fluids. Separate tests were carried out using drilling fluid alone and the full operational sequence. Filtrate loss and permeability measurements combined with interpretative analyses to understand what happened in the near-wellbore. Micro-CT "change maps" gave 3D visualisations of the thickness of operational fluid cakes and extent of retention/clean-up – valuable insights into factors that influence hydrocarbon recovery.All drilling fluids tested had "normal" filtrate loss volumes, with one having notably higher losses with a particular formation. Normally this would be considered a bridging issue and "fixed", but those tests showed comparable or slightly lower alterations in permeability. Analysis showed that, despite deeper constituent infiltration, they were not contributing significant extra damage or retention; the nature of the drilling fluid attachment and cake seemed to be more relevant here than depth of invasion. Other examples will illustrate that the impact of drilling fluid infiltration and retention can range widely, and that there are more key factors than simply filtrate loss volume.Results showed that focusing on the metric of filtrate loss alone may increase risk during drilling fluid selection. Understanding the relationship between filtrate loss, permeability/inflow alteration, retention/clean-up after production is important in selecting fluids as well as giving a better understanding of where improvements can be made. 3D visualisations of the alterations caused by drilling fluid allow conclusions to be drawn when previously there would be speculation.