York field is located in the Southern North Sea (SNS), within the UK offshore license blocks 47/2a, 47/3a, 47/3d, and 47/3e. The field lies 40 km east of the Humberside coast in a water depth of 42 m, approximately 25 km northeast of the Yorkshire coast and adjacent to the Rough Gas storage field. York field has been in production since 2012. The field consists of four production wells from a normally unmanned installation (NUI). All four wells have active downhole sand control and long horizontals drilled and completed in the reservoir section. This paper presents the design phase and execution for sand screen completions and provides an in depth process of the selection criteria for the lower completions performed in York field. Findings are presented along with analyses of the design methodology and installations to date. In addition, results of the well post-completions data are discussed.
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.
AbstractThis paper aims to discuss completion of deepwater open-hole gas wells that were completed using an alternate paths system (APS) and a state-of-the-art viscoelastic surfactant (VES) carrier fluid. The wells presented multiple design and operational complexities such as high bottomhole temperature, narrow fracturing window, extended horizontal laterals, and unstable shale zones. Operational and design steps considered to overcome these complexities are discussed, making this literature a resource that maps obstacles and presents viable solutions faced in any similar operation. These complexities combined with deepwater operational requirements and economics made cost of failure unacceptable.Two 8.5-in. openhole depleted gas wells up to bottomhole temperature of 230 °F were completed with gravel pack treatments using a VES carrier fluid to counter sand settling, minimize friction pressures, and optimize fluid viscosity. The operations pumped 200% excess proppant compared to design volume to ensure complete packs downhole, countering any thief zones or open-hole washout regions. Returns were taken through the BOP via mud line to avoiding high fluid friction in the choke line. In one case, the riser was displaced with lighter base oil to reduce the bottomhole pressures.Using the alternate path system and VES carrier fluid proved to be highly successful in these wells, as compared to the pre-drilled liners and standalone screens used previously in the same field. Complete packs were obtained within narrow fracture gradient windows in all cases. After reversing out the slurry, a filter cake dissolver treatment was also performed to decrease the flow initiation pressure for the well. Case studies have been presented elaborating completions plan and execution of open hole gravel pack treatment for two 8.5-in wells.This literature is a case study elaborating operational procedures that have proved to be successful in performing open-hole gravel packs under complex constraints. This paper serves as a reference, highlighting obstacles faced and presenting viable solutions for any similar operation.
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.
AbstractOne of the most common challenges faced by well operators worldwide is extending the lifetime of their aging platform wells. The initial well construction, operational loading and time-dependent deterioration of a well through field life are all key factors that need to be understood to establish the remaining capacity of a well. However, often these factors are not fully understood and consequently costly decisions to repair or abandon wells can be made unnecessarily, or in some cases critical wells or operations on wells are not identified, risking structural collapse of a well. To address these issues, this paper describes the factors that influence the integrity of the well, and presents advances in the approaches to understand and evaluate the condition of a well and hence better evaluate remaining capacity. Methods, Procedures, Process: Typically, corrosion of the casings is taken as the key parameter to establish a well's remaining capacity. However, as demonstrated in this paper through an analytical evaluation, the axial loading in the well is another key parameter that needs to be understood. A range of factors affect the well axial loads based on well construction and deterioration is considered, including: Weight of casing hung off wellhead during installationLevel of axial support provided by casing shoeCement levelsChanges to well configurationChanges to well service (Producer to Injector)Changes to operating temperatures and pressures through field lifeCorrosion and other deterioration of the conductor and casingsThis information can, however, be difficult to obtain due to incomplete or inaccurate construction records or difficulties in taking direct measurements or inspecting a well. This paper demonstrates the influence of each of these variables on the capacity of the well, how the uncertainty in these variables affects this assessment, and consequently the overall uncertainties in establishing the remaining capacity of a well. Results, Observations, Conclusions: Having established the limitations and uncertainties of an analytical evaluation and the need to establish well axial loads, the paper also proposes a method to characterise the axial loads in a well, including a proposed technique for in-field measurement as an input to establishing a well's on going fitness for service alongside corrosion measurements. Novel/Additive Information: Overall, the paper presents an improved approach to establishing the suitability of a well for life extension based on an improved understanding of the influence of well loads, with widespread application to aging platforms in the North Sea and globally.
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.
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.
AbstractSand production has been a critical factor regard the safety and the economics of many oil and gas fields. The first acoustic sand monitor was commissioned in 1995. Since then, a significant amount of time and money have been spent on controlling sand production.A critical factor has always been accuracy and reliability of the systems, with different approaches used to accommodate the risk and the challenges different fields present.This presentation will look back at how things were done in the beginning, what we have learned, and how things have changed. It will also cover the technical evolution since then.We will look at the challenges still to be solved, and the experience gained in the areas of sand production, sand transport and sand monitoring.The presentation will be supported by field cases.
AbstractDrilling optimization is an engineering strategy to drill wells more productively and efficiently. Specific objectives of directional drilling are good hole quality, firm directional control, high angle-build capacity, maximal durability, optimal rate of penetration (ROP) and low non-productive time (NPT). This can be achieved through a perfect combination of well design, mathematical drilling models, drilling data analysis, and applications of new and high techniques.High ROP in safe and stable drilling conditions is the most valuable optimization objective. Our study mainly focuses on ROP improvement in directional wells. In this paper, three directional control technologies: steerable mud motors, targeted bit speed systems (TBS) and rotary steerable systems (RSS) have been investigated. Average ROPs with implementation of these technologies have been compared by analyzing more than 30 wells drilled in Russia.When drilling directional wells with a steerable mud motor, the number of sliding intervals has to be increased to achieve higher dogleg severity (DLS). It results in decreased total ROP, an averaged value in sliding and rotating operations. Conventionally, ROP in rotating intervals is roughly estimated to be two times higher than ROP in sliding intervals. From the analysis of several field cases, a model to describe the total ROP has been developed, where the DLS influence is taken into account. It provides useful knowledge for wellbore trajectory design in terms of achieving high ROP.Nowadays, factors as bit types, tooth-wear and hydraulics, formation characteristics, drilling mud properties and operational conditions, etc. are considered to optimize rotary drilling. However, the influence of wellbore trajectory, inclination and azimuth in particular, is ignored in existing ROP models. In this study, a traditional multi-regression Bourgoyne and Young ROP model has been extended by dogleg severity factor (DLS) to link the wellbore trajectory design to ROP optimization. The proposed empirical model has been applied to several drilling data sets. Calculated ROP values were compared, and the increased accuracy was seen for all cases. This model can be used for wellbore trajectory planning, more precise ROP prediction and optimization, and post-analysis of drilled wells.
AbstractReal-time centers first appeared in the 1980s, became increasingly accepted in the 1990s, and are currently commonplace. They are an indispensable tool for complex operations and help avoid unplanned and sometimes potentially catastrophic events. These centers are commonly used offshore, particularly for deepwater operations, with a wide range of workflows specifically designed to help reduce the risk of undesirable events. The bow-tie risk assessment method is a risk mitigation function that is widely used in workflow design. It enables the design of workflows based on the number of options or solutions available to avoid or mitigate an undesirable event. In unconventional and other operations, these events can be difficult to identify because their consequences can be less obvious, particularly in more streamlined, standardized operations. This paper demonstrates the use of the bow-tie risk assessment method to create workflows specifically designed for these situations. In this workflow method, the event in question is placed in the center of a bow-tie shape, with two wings growing in size to the left and right. The left side represents options to avoid the event; the right shows mitigation opportunities. This approach is well-suited to operations with many unexpected events having unique, non-standard situations. Because the resulting workflows provide solutions for before, during, and after the event has occurred, scenarios are presented to avoid the event, address it if it occurs, and mitigate it after it has passed. A new way of using this method developed from the implementation of real-time centers in unconventional assets located outside of North America, in which operations are used with many repetitive and standardized procedures. In these operations, unexpected events are less common, and the need exists to further improve efficiencies and operational delivery. This paper demonstrates how workflows can be designed using the bow-tie methodology and rethinking the event concept. By defining the center of the bow tie, workflows can be designed to have a measurable effect on the overall operation rather than only in a specific situation. This rethinking is possible because the applicable real-time centers are being implemented at the same time that new unconventional assets are being developed. It is relatively uncommon in North America to deploy real-time centers after assets have standardized processes or have been in operation for a period of time. In other areas, however, real-time centers are implemented while the asset is going through trial and error, providing a unique opportunity for the workflow design process to mature with the rest of the operation.