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Decide which pieces of work are suitable for co-production and what can and cannot be achieved by involving people in this way.
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Develop and agree with your public contributors a role description which clearly states the time commitment expected from them, the length of their involvement and payment details (a template role description is available). Enter your email address to subscribe to this blog and receive notifications of new posts by email. By Sean Stright, Nelson Tears, Gregory King, ExxonMobil Development Company; Vikas Srivastava, David W.
A large number of subsea production wells have been drilled, but to date, there has been limited industry experience of redrilling subsea wells even though redrills have become routine in platform and surface wellhead applications.
Figure 1: The Beryl field, about 200 miles northeast of Aberdeen, began production in 1976 from the Beryl Alpha platform.
The article will describe how the unique challenges of redrilling three subsea wells were overcome in old and declining fields where the original wells were designed and drilled with limited consideration for redevelopment of the fields through reuse of existing wells. There has been limited industry experience of subsea production well redrills, and significant lessons learned will be shared.
The operator’s affiliate in the UK North Sea, Mobil North Sea, is the operator for the Beryl, Ness, Nevis, Buckland and Skene fields, which constitutes the Beryl field.
Production from the Beryl field started from the Beryl Alpha platform in 1976, and the Beryl Bravo platform started production in 1984.
In 2007, the North Sea Beryl Drilling Campaign was temporarily suspended to reevaluate the drill-well inventory. The mooring design for any location is subject to many factors, which change over the life of a field.
As a result, the metocean data quality and analysis has improved, and the mooring designs will be affected. An expanding footprint of subsea infrastructure creates a further challenge to maintain sufficient vertical clearance of mooring lines from the subsea infrastructure. In the absence of an active drilling campaign, the ability of a mobile offshore drilling unit (MODU) to position over the modified infrastructure and maintain adequate clearances to the infrastructure may not have been fully evaluated. For mooring lines that span over subsea infrastructure, it is common to establish a minimum tension requirement to maintain the required vertical clearance.
While subsea buoyancy provides a solution to the vertical clearance issue, the addition of mooring hardware in the mooring line creates another potential issue. Throughout drilling operations, the primary hazard to the integrity of the production flowlines and gas lift lines within the immediate area of the wells being drilled was the potential for dropped objects – either through the moon pool or over side crane work. The MODU was in continuous contact with the Beryl Alpha platform, allowing all subsea lines to be shut-in immediately prior to any heavy lift. Figure 2: Welded components of a subsea wellhead system have inherent flaws from the fusion process.
Offshore drilling and workover operations impose fatigue in the subsea wellhead and casing system when the system experiences cyclic stresses induced by the motions of the MODU and riser.
The fatigue assessment methodology applied to analyze the fatigue life of the subsea trees, wellheads and casing connectors and welds is discussed below.
First, a dynamic stationkeeping analysis is conducted to obtain the resulting motions of the vessel’s center of gravity as it is acted upon by the wind, wave and current environment.
For the riser analysis and well system fatigue analysis, the calculated vessel wave motion RAOs are translated to the top of the riser. A global riser analysis includes the vessel motions, actions of waves and currents, tensioning system, slip joints, riser joints, and wellhead stack; structural and inner casing strings below the mudline and soils is then performed. In the global riser analysis, tubulars and other components are modeled using beam elements of equivalent weight and stiffness with non-linear spring constraints along the structural casing to model the mechanical behavior of the soils. Although the global riser analysis may be carried out either in the frequency or time domains, the frequency domain analysis is preferred for ease and efficiency.
A wellhead and casing system analysis is performed to determine the response of the wellhead stack and casing system to the loads imposed by the riser, which were obtained from the global riser analysis. The analysis simulates the casing and wellhead installation and cementing sequence to capture the locked-in stress state in the system, followed by the internal and hydraulic pressurization. For each sea state, component sectional force and bending moment ranges are obtained at the cross-sections containing the hot spots (reference cross-sections). Stress concentrations exist at geometric transitions and misalignments of well system components, welds and casing connectors. The hot spot reference stress ranges for each sea state (weather bin), and its annual probability of occurrence are critical inputs to the subsequent fatigue analysis.
To evaluate fatigue resistance, the material fatigue capacity is defined in terms of S-N curves. Figure 3: A digital inclinometer is mounted on a base plate of a blowout preventer stack, which is wired to a remotely operated vehicle for continuous surface read-out.
When a frequency domain approach is used to obtain the dynamic response of the riser at a given reference section, the fatigue damage can be expressed in a close form. Conservatively, bending moment and shear are assumed to be in phase and the shorter Tz from either the bending moment or shear is used to calculate the number of cycles for estimating the fatigue damage. The methodology can be applied to two levels of fatigue assessment: fatigue screening and detailed fatigue analysis. The fatigue screening analysis is intended for obtaining quick estimation of the fatigue performance of the wellhead and casing system using simplified and conservative assumptions. The detailed analysis is more rigorous with more realistic assumptions than the screening level analysis. The cumulative fatigue damage at each circumferential location is then calculated by summing the product of the unweighted damage at that location with the probability of occurrence of each weather bin for which the riser is connected. Furthermore, the rate at which fatigue damage accumulates at each of the critical locations depending on the season of operations may be calculated.
In this case, additional life for crack propagation to an unstable size can be calculated using a fracture mechanics approach. For a reentry campaign, the analysis must consider both anticipated fatigue damage for the proposed work and the fatigue damage accumulated from prior campaigns. When high fatigue loading is anticipated, a preloaded wellhead system can minimize the fatigue effects on the wellhead and surface casing by rigidly locking the high-pressure housing to the low-pressure housing.
The location of the top of the surface casing cement can also impact the fatigue assessment results.
For a reentry campaign, preloading the wellhead or remedial cementing are not feasible options. In a risk assessment for a reentry or workover operation, failure is usually defined as a loss of containment or structural collapse of the well system.
The S-N curves used to evaluate fatigue resistance are associated with different definitions of failure (crack initiation for parent material and through thickness crack for welds) that are not directly related to loss of containment or structural failure.
In BS 7608, “Fatigue design and assessment of steel structures,” it is suggested that a normal distribution may be assumed in calculating the probability of failure associated with a particular value of fatigue safety factor. Slot recovery operations from floating rigs presents several unique challenges over land or fixed platform operations.
Subsea well reentries involve recovery of items that are very close to the full bore of the BOP, including subsea test tree assemblies, casing hangers and seal assemblies. In the North Sea, the combined effect of high seas and shallow water depth (360 ft) makes vertical motion control of the drill string especially challenging. Seal assemblies vary in design but generally are designed to serve three functions: provide a primary pressure barrier in the casing hanger annulus and lock to the casing hanger and the wellhead. Some older-style wellhead systems have locking mechanisms for which recovery of the seal assembly years after installation was not envisaged. For wells in the Beryl North Sea campaign, recovery of seal assemblies involves pulling seal assemblies 15 years after initial installation and after exposure to high temperatures and production loads. Leaving the lock ring in the wellhead introduces a risk of damage to internal seal areas when recovering casing hangers and will prevent access to set bore protectors and seal assemblies. If the lock ring cannot be recovered by conventional means, an extensive evaluation and risk assessment of the well barriers needs to be made before unlatching the BOP connector and recovering the lock ring with an ROV. Risk mitigation is well-specific, and no generic rules can be followed to state when it is safe to remove the BOP. Recovery of casing by cutting and pulling is a proven method of performing a slot recovery.
Utilizing a marine swivel (landed off at the wellhead) is a simple and commonly used method to prevent rig motion from being transmitted down the drill string. In the absence of a marine swivel, it will be necessary to use a cut-and-pull spear, where a grapple is engaged inside the casing stub, and tension is applied to the top of the casing stub, preventing transmission of rig motion of the casing cutter. For subsea slot recovery work, it is highly likely that multiple cut-and-pull runs will be required.
Furthermore, heavier and stronger drill strings that provide high overpull capacity are generally not shearable with conventional blind shear rams. Whipstock sidetracks have routinely been used to establish a sidetrack from a wellbore for subsequent drilling operations. Prior to running the whipstock, a drift assembly simulating the length, stiffness and configuration of the whipstock assembly is run to verify the whipstock is capable of being run to the planned depth. Single-trip whipstock assemblies, which allow both running the whipstock and milling a window with a single assembly, may be the quickest method of establishing a sidetrack.
Consideration should be made for localized doglegs at the wellhead area when determining which system should be used.
Milling of a window that will enable passage of all drilling assemblies requires precise control of weight on bit (WOB). As with running whipstocks, environmental limitations should be considered for milling operations.
Metal swarf created by casing milling is likely to accumulate at the BOP area due to the larger ID of the BOP and riser, and in the cavities in the BOP area capable of capturing debris.

If the jet sub is larger than the internal diameter of the wellhead profile below, a drill pipe hang-off tool designed for the wellhead profile can be run below the jet sub to prevent risk of damage to the jet sub and wellhead. Both the abandonment and subsequent completion operations must be performed with the tree connected. The only opportunity to reduce the fatigue damage was to remove the tree for sidetrack drilling operations. The whipstock was fished from the well on the first attempt using a custom-designed box tap that was shipped with the whipstock on load-out.
After confirming the well was static, the annular preventer was opened and left to relax for one hour prior to pulling the seal assembly through it.
Despite all risk-mitigation measures, the outer lock rings could not be recovered, as they did not return to their original shape – the OD of expanded lock ring was larger than the minimum ID of the BOP. No swarf was observed at the BOP upon recovery to surface, and there was no wear or damage to the BOP, confirming the jetting was effective. Despite extensive up-front planning, a subsea well reentry will always have higher potential for nonproductive time and equipment issues than a new well. The keys to success for a reentry program are to develop a realistic well plan that does not rely on a “success-based” outcome for each well operation and that provides relevant well data at each operational step to help make informed decisions on forward plans. The well plan also needs to give clear operating limits for when to continue and when to cease operations. Effective preservation of the original wellbore components can safely extend the service life of the entire operating asset. Exxon Mobil Corporation has numerous subsidiaries, many with names that include ExxonMobil, Exxon, Esso and Mobil.
API Recommended Practice 2SK, “Design and Analysis of Stationkeeping Systems for Floating Structures,” Third Edition, October 2005, Addendum May 2008. Echosmith, New Politics, Katy Tiz, Big Data e altri, mettono il loro talento al servizio della nuova espansione di The Sims 4! The Sims 4 Al Lavoro!* e il primo expansion pack lanciato per The Sims 4 che ha visto la collaborazione di alcuni tra gli artisti emergenti del momento, che si sono cimentati a cantare le loro ultime hit in Simlish – la lingua ufficiale di The Sims. Questo sito utilizza cookie, anche di terze parti, per migliorare l'esperienza utente, motivi statistici e pubblicita. One of the problems with live production is that most cameras have not really been designed for live production, so they don’t have the features that we need such as a large bright viewfinder, talkback, tally, optical fiber plus almost all cameras are made from plastic.
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There are a number of things that need to be considered when deciding to work in a co-produced way. For example, don’t have meetings at a time that excludes public contributors from attending or from taking part in the background thinking and development of a project. The focus of this article is to highlight the key aspects of redrilling a subsea production well to extend field life. They will be of wider application as the number of subsea wells increase along with the requirement to maximize recovery and extend field life. Subsea developments include Ness, Nevis North and Nevis South, where wells are tied back to the Beryl Alpha platform and date back as far back as 1996. In 2010, a semisubmersible was contracted for a five-well redevelopment campaign, which consisted of two workover operations and three abandonment and sidetracks. Rather, the quality and accuracy of metocean data, hindcasting methods and the numerical models used to develop the design criteria have all improved. For the Beryl field, this has resulted in current mooring designs being assessed using more stringent metocean criteria than used for prior campaigns. For an older field, where new wells may not have been drilled in a long time, routing of subsea flowlines, equipment replacement and general field maintenance may cause the footprint of the subsea infrastructure to grow. However, with more stringent metocean criteria as the assessment basis, along with a growing subsea infrastructure footprint, specifying a high minimum tension to protect flowlines may not result in appropriate mooring analysis results. Loss of subsea buoyancy in conjunction with a mooring line failure creates further failure scenarios that should be considered. The local production affiliate, after extensive review and risk assessment, required 20 meters vertical clearance to protect their infrastructure, so this clearance criteria was used for the campaign. Based on mooring analysis in worst-case metocean conditions, it was determined that it was not feasible to maintain line tension in excess of 100 kips in all environmental conditions. This is a conservative assumption to ensure the buoyancy is not completely relied upon to protect infrastructure and a loss of subsea buoyancy alone does not result in a mooring line clashing with infrastructure.
Loss of a single smaller buoy would not result in complete loss of vertical clearance to the subsea infrastructure.
Strictly applied, previously established operating procedures governed the movement of any MODU lift over water. Emergency shutdown (ESD) could be initiated if required via an open communication link between the MODU and the Beryl platform control room during dropped-object exposure periods. Vertical clearances of mooring lines to subsea assets were assessed in the mooring analysis for these rig positions, and as often, minimum vertical clearances are observed while at the heavy lift standby location. A fatigue screening analysis can quickly estimate the fatigue performance of the wellhead and casing system using simplified assumptions. In shallow water, a shorter riser makes the fatigue load transmission to the wellhead and casing more severe; therefore, shallow-water operations under harsh environments, such as those in North Sea sites, generate more severe fatigue than operations in deeper waters under mild environments.
The accumulation can lead to a fatigue crack, which could propagate and lead to loss of integrity of the component. Vessel motions are dependent on vessel characteristics and whether the vessel is moored or dynamically positioned. Depending on the mud weight and environmental conditions, minimum riser tension analysis is performed to determine required slip joint tensions and corresponding static and dynamic global loads (moment, axial and shear forces) along the riser system. Static P-Y curves are used to model the soil behavior for the strength analysis, and cyclic P-Y curves are used to model the soil behavior for the fatigue analysis.
In the frequency domain approach, it is assumed that the wave frequency response can be represented by a narrow-banded Gaussian process with Rayleigh distributed peaks.
All components in the wellhead and casing system are modeled as concentric pipe-in-pipe (PIP) elements in a finite element package with appropriate geometric and material properties. This is followed by applying the fatigue loads obtained from the global riser analysis at the top of the PIP model for each sea state. Following this, nominal or reference stress ranges for the fatigue-critical sections are calculated for each sea state by using the corresponding cross-section geometric properties. The SCFs are calculated using detailed finite element analysis for fatigue-critical locations assuming isotropic linear elastic material properties. The fatigue assessment is based on the cumulative damage model (Miner’s rule), which is equally applicable to welded and mechanical connectors, provided their corresponding fatigue resistances are properly characterized. That is in the detailed fatigue analysis, the reference stress range, zero crossing period, the probability of occurrence of each of the fatigue weather bins, the riser connected days in each season, and the riser disconnect criteria are all used to calculate the cumulative fatigue damage at a number of circumferential location for each of the fatigue critical areas. Therefore, the predicted fatigue life is predominantly related to propagation of these flaws. There is usually no opportunity to perform physical testing on the materials and welding procedures used for the original installation. Some conventional wellhead systems are not preloaded, and the required tensile load to lock the high-pressure housing to the low-pressure housing is passively applied by the weight of the surface casing string. If the top of cement is not well documented, a conservative assumption for the location of the top of cement should be used in the fatigue assessment.
Thus, the type of system wellhead installed and details of the surface cement job (cement volume and ROV observations during the job) are important considerations in the overall assessment. In practice, the fatigue analysis does not provide a quantifiable relationship between the calculated fatigue safety factor and the probability of loss of containment or structural failure of the component.
Additionally, the S-N curves used are typically the “mean minus two standard deviation” curve, based on regression analysis of test data.
However, BS 7608 does not provide a basis for the use of the recommended normal distribution assumption.
The planned riser connected days for all wells in the North Sea Beryl campaign were within the North Sea experience envelope for the respective wellhead systems.
Performing precise casing-cutting operations from a heaving rig can cause damage to either the wellhead or the bottomhole assemblies being used. Some assemblies may have been designed for the original installation, and recovery or reuse of these components many years after initial installation may not have been considered in the engineering design.
Locking mechanisms vary in type, and the issues outlined in this article are not associated with every wellhead system. A locking ring expands in a profile beyond the nominal inner diameter (ID) of the wellhead to provide a path for the required reactive force between the hanger and seal assembly. The ring does not retain any of its original properties and likely cannot be pulled back through the same bore ID that it could on the original installation. Conventional fishing tools are not designed to recover lock rings while inside the wellhead.

Recovery of a lock ring with an ROV may not be avoidable and should be considered as a high-probability scenario before starting any subsea reentry campaign.
When cutting casing from a MODU, the rig motion must not be transmitted to the casing-cutter assembly.
When this situation was encountered in the North Sea campaign, a conventional mud motor was placed between the grapple and the casing cutter to cut the casing. Jarring is generally limited as extensive jarring could cause damage to the subsea wellhead. When recovering casing in smaller sections, the minimum casing cut length will be determined by the length between the grapple and the casing cutter. The primary difference between a whipstock deployment for a subsea well compared with a surface or fixed platform is the motion of the drill string. A significant difference between the whipstock and drift assembly is the shear bolt attaching the whipstock to the milling assembly. However, relative to a multiple-trip system, these assemblies are generally longer and stiffer because of the additional casing mills in the assembly. Factors include wellhead inclination, taper of casing cross overs below the wellhead and changes in geometry through the BOP and wellhead. A riser boost line can enhance hole cleaning, but the boost line is commonly above the BOP and would not sufficiently boost the flow rate across the BOP.
All of the concepts outlined here were factored into the well designs and operations for all three wells drilled in this campaign. Primary attention was for wells with horizontal trees, as the detailed analysis showed that the connector between the tree and wellhead had the shortest predicted fatigue life. For the subsequent run and for all subsequent work with whipstocks, a two-trip assembly was used. Prior to pulling the seal assemblies, a drift assembly was run to confirm fullbore drift through the riser and BOP.
This outcome was anticipated based on an engineering review of the wellhead system, and the appropriate risk assessments were performed during the well-planning phase for this outcome. Reentries involve reuse, refurbishment and preservation of a certain component of the original wellbore.
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The viewfinder’s LCD is extremely bright and has a very wide viewing angle so it is perfect for use even in direct sunlight. This means you can use high quality photo lenses for smaller setups or high end broadcast ENG lenses for large live broadcasts using an MFT to B4 lens mount adapter. We at the West of England AHSN have committed ourselves to being guided by these principles and working in a co-produced way. Three newer subsea fields were developed starting in 2001, including Buckland, Skene and Lewis 1, which is an extension of the Nevis South Development. In the North Sea, the metocean criteria used as a design basis for mooring designs have evolved, resulting in more conservative environmental criteria at locations such as the Beryl field.
Further, the assessments have become site-specific to fields within the North Sea, and the databases continue to grow with new data. A mitigation that can be employed is use of subsea buoyancy of the mooring lines to provide sufficient vertical clearance. Although API RP2SK provides explicit design criteria, it also states, “to determine clearance criteria, many factors should be considered, such as environment, water depth, and risk of injury, asset and environmental damage, etc.
However, in the event of metocean conditions where the minimum line tensions cannot be maintained on the leeward lines, the infrastructure is still protected by the buoyed mooring line. The interactions between the floating vessel, riser, wellhead stack (lower marine riser package), BOP, tree, and low- and high-pressure housings), casings and soils are modeled to evaluate the fatigue at fatigue-critical locations, both above and below the mudline. In either case, the vessel heading with respect to the wave direction is defined, and its wave motion response amplitude operators (RAOs) are calculated for use in stationkeeping and riser analysis. The soil and casing interaction is modeled with non-linear spring elements using site-specific cyclic P-Y curves for the soil.
The section properties used to calculate the reference stress and stress ranges must be consistent with those used in calculating the stress concentration factor (SCF) for the hot spot. In this model, fatigue damage at a location from various sea states or sequential drilling and workover operations (riser connected days) are additive.
If the estimated fatigue life meets design requirements, the fatigue assessment is considered complete and detailed fatigue analysis is not required.
Site-specific seasonal and directional fatigue weather bins with associated probabilities of occurrence are developed.
On the other hand, in machined components, most of the fatigue life is related to initiating a crack since the parent material generally contains only structurally insignificant flaws. Therefore, conservative assumptions may need to be made related to the specifications of the parent material and welds in the absence of the physical testing to verify the S-N curve characteristics. The subsea wellhead must be reused, and extensive effort is required to ensure protection of the wellhead and all seal areas.
Furthermore, casing recovery will inherently cause metal debris to be introduced into the wellbore, which may introduce risk of damage to BOP or wellhead seal areas.
Excessive cutter motion will cause damage to the cutter and prevent a sufficient quality cut to be made to recover the casing. When problems are encountered retrieving casing, the casing string may be cut in smaller sections to maximize the tension applied at the cut point. Rig motion, especially when the drill string is in slips, can cause cyclic loading on the shear bolt. Furthermore, the differential angle between the flex joint and wellhead should be minimized and closely monitored while running the whipstock through the BOP and wellhead. In conditions where high rig heave is being encountered, a passive heave compensator may not be capable of providing the required WOB control. A combination of fullbore jetting assemblies with magnets and junk baskets below the jet sub can remove the excess metal debris. An annular preventer was then closed, and the BOP was drifted again after 15 min to verify the preventer was fully open. OD jet sub with a pocketed string magnet that captured debris within pockets on the tool itself. Problems encountered may not be the result of current operations but could be inherited from prior operations (drilling or production).
If that component is compromised, either from previous or current well operations, the most economic decision may be to cease the operation. Nothing in this paper is intended to override the corporate separateness of these separate legal entities. M., “Fatigue Assessment of Subsea Tree Connectors and Wellheads,” OMAE 2011 – 49853, Proceedings of the ASME 2011 30th International Conference on Ocean, Offshore and Arctic Engineering, June 2011.
The Instrumentation of the Conductor of a Subsea Well in the North Sea to Measure the Installed Conditions and Behaviour Under Load.
Overview of the Work Carried Out During the North European Storm Study; the Hindcasting of North Sea Metocean Parameters. All drilling operations required reuse of the existing wellhead, slot recoveries requiring cut and pull of casing, and whipstock sidetracks.
Conservative criteria should be established based on these considerations (API 2005).” Thus, the clearance criteria used by the North Sea team was consistent with this expectation.
It was not possible to design for mooring line tensions below the minimum tension specifications concurrent with complete loss of buoyancy. The platform control room operator also had clear instructions to initiate a field ESD on instruction from the MODU. The fatigue damage is calculated at discrete locations around the circumference of a component for each of the seasonal and directional weather bins. For a machined component, such as a tree connector or casing connector, overall fatigue life corresponding to a through thickness crack can be higher than that calculated using the parent material S-N curve, if the S-N curve corresponds to the initiation of a stable crack (Figure 2). This can be problematic when pulling and setting seal assemblies or performing any work at the wellhead or BOP. When this is done, the casing hanger that was normally used to support the marine swivel may have been removed from the wellbore. Prior to running the whipstock, the rig may need to be repositioned to achieve the lowest flex joint differential angle.
The seal assembly was then retrieved with the same annular closed to assess trapped pressure in the annulus. A “junk basket” was used at the bottom of the assembly to catch any debris that fell below the magnets.
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Attempting to work in excessive sea states could result in permanent damage of the wellbore.
Consideration must be made for acceptable environmental conditions for running the whipstock; otherwise, the whipstock may be lost in the wellbore.
The whipstock was being run very slowly, and at no time could excessive down weight be observed on any rig weight indicator. Between each well, the BOPs were thoroughly stripped down and inspected due to the potential for damage caused by the metal debris.

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