Patel, Kailesh (Total E&P UK LTD) | Ugolini, Jean-Marc Pierre Hugo (Total E&P USA, Inc.) | Millancourt, Francois Jean (ADCO) | Falconer, Chris (Total E&P UK LTD) | Soyeur, Christophe (Total E&P UK LTD) | Neillo, Valerie (Total E&P UK LTD)
The West Franklin HP/HT Field discovered in 2003 by the well 29/5b-F7z was drilled on a simple structure defined using the 1996 Elgin/Franklin 3D seismic - vintage data which has since been superseded by state-of-the-art seismic processing techniques. The original PSTM displayed relatively continuous seismic reflectivity with large uncertainty on imaging and interpretation.
The highly productive porous sandstone interval within the Upper Jurassic Fulmar Formation was identified as a high amplitude reflector due to a strong decrease in impedance. Anisotropic PSDM processing followed by an acoustic inversion study highlighted the probable extension of this ‘Porous Zone' to the west and underlined the high potential for a second appraisal/development well.
Positive results from the second well 29/5b-F9y in 2007 showed dramatic thickening and improvement in reservoir quality to the west and initiated additional PSDM processing of the original 1996 data. Following developments in tomography and migration algorithms, strong imaging improvements were observed from the integrated anisotropic velocity model updates and by reducing the amount of destructive interference from multiples. The resulting interpretation allowed for a better understanding of the salt tectonics and in predicting Fulmar reservoir thickness to the west.
A 7km Long Offset 3D survey acquired by CGGV in 2009 with subsequent PSDM processing is bringing further imaging improvements over areas of amplitude degradation leading to potential upsides. A first 4D monitor acquisition over Elgin/Franklin in 2005 (before production had started on West Franklin in 2007) is being followed-up by a second 4D monitor in 2011, aimed at providing additional information on the depletion pattern around the field. Such strategy in ongoing investment in seismic data will further unlock the resource potential over and around West Franklin in the coming years, ensuring a mature area remains in the spotlight.
In October 2010 the deepest set sealed multilateral junction in the industry was installed at 6900 m MD in Oseberg South well 30/9-F-9 AY1/Y2.
The differential pressure across the junction in the well is expected to be in the range of 250 bars. To meet this pressure requirement, a multilateral (ML) junction rated to 370 bars was identified. The high pressure junction components and entire multilateral system has undergone an extensive testing and qualification program, including several component tests and a full scale system interface and integration test.
A 10 ¾" pre-cut window with an outer aluminium tube was installed as an integral part of the 10 ¾?? liner. The plan was to perform the milling operation through this window. A stuck string incident during the 10 ¾?? liner installations accidentally caused the liner to drop in hole. The liner ended up at the wrong orientation, and the window could consequently not be used.
The mainbore was drilled to TD at 8583 m MD and the 7?? liner was run and cemented. After the liner perforation the MLT operations started with the installation of a multilateral anchor packer to allow for installation of a latch interface assembly (LIA) and milling system. The LIA was installed and locked into the multilateral packer on a separate run.
The milling operation was done in a two step operation with milling of a 1st pass window using a 10 ¾?? milling machine prior to installation of whipstock and performing the 2nd pass milling operation.
The lateral branch was drilled to TD at 8258 m MD and a 5 ½?? screen completion was run and dropped off into the 8 ½?? open hole. The drilling whipstock was retrieved from the well and a completion deflector was installed. The junction was finally stung into the deflector, simultaneously as an open hole seal
stinger entered top of the screen liner in open hole, tying the branches together.
A 6900 m long upper completion string with inflow control valves was finally installed to allow for surface control of the two branches.
Introduction to the Oseberg South Field
The Oseberg South platform is located in the North Sea, 130 km west of Bergen, Norway (Ref fig 1). The platform commenced production in the fall of 2000. The Oseberg South field, consisting of several geological structures south of the Oseberg main field, is developed with an integrated drilling, accommodation and production platform on a steel jacket. There are 32 wells planned from the platform. Oseberg South field's plateau production is app. 5400 m3 (34 000 barrels) per day. Sea depth is about 100 meters. The oil is transported via the Oseberg Field Centre and Oseberg transport system to the Sture terminal.
Well 30/9-F-9 Y1/Y2 was planned to target Upper Tarbert (UT) and Middle Tarbert (MT) at the G-Central structure. The well was planned as the first oil producer, and the target area is located in the southern parts of the structure (Ref fig 2). The well was planned as a MLT well where the first branch (Y1) will produce Upper Tarbert oil/gas and the second branch (Y2) Middle Tarbert oil.
Upper Tarbert contains about 70% of the expected oil and gas reserves and generally consists of wave-reworked lower-upper shoreface siltstones and fine-grained sandstones with relatively poor reservoir properties (average values for porosity and permeability are typically in the order of 5-18 % and 0.2-20 mD, respectively). Upper Tarbert deposits have high degree of variability, from high gamma ray sands and silts to very tight calcite cemented stringers.
In general the Middle Tarbert Formation is sub-divided into two parts: MT1 and MT2. MT1 is interpreted as near shore deposits while MT2 was deposited in a more energetic tidal environment. The porosity is within the range 12-26 % while the permeability varies from 50 - 2500 mD.
Routine testing of wells with electric submersible pumps (ESPs) is usually conducted monthly to monitor liquid rates, water cut (WC), and gas/oil ratio (GOR). This monthly testing is the most common form of production and reservoir surveillance and is implemented in even the most mature fields where cost control generally takes precedence over reservoir surveillance.
However, this technique has its limitations. The most common limitation is insufficient testing duration to capture a representative sample of reservoir fluids. This testing duration issue is often the case in low-flow rate and deep wells, which require several time-consuming whole or complete liquid holdup periods. Other potential problems include insufficient resolution or repeatability to identify trends in liquid and water-cut rates over short periods of time. To date, the only method
for resolving these issues has been to install permanent multiphase meters on each well. Although this method has been implemented in some fields, it is uneconomical for most wells. An analytical method is described for a flow rate calculation that can be implemented in wells produced with ESPs and equipped with downhole gauges and real-time monitoring systems.
These downhole gauges and real-time monitoring system provide continuous real-time virtual flow rate measurements and therefore, both liquid and water-cut trends, which deliver the required resolution and repeatability to support both well performance diagnostics and near-wellbore reservoir analysis. This technique, which has the advantage of being valid for both transient and steady-state conditions, provides instantaneous flow rate data when used with real-time data. Case studies presented will illustrate model calibration and its application to back allocation and transient analysis. Examples are provided to show how the data can be used to rapidly identify changes in productivity index and reservoir pressure across the drainage area; thereby, enabling real-time production optimization.
Increasing use and complexity of subsea installations has put focus on the costs of maintaining these systems. In addition, access to these systems is sometimes limited by adverse weather and ice conditions. Conventional methods for intervention, maintenance and repair (IMR) using surface ships and ROV's are very expensive furthermore are response and mobilization times slow.
To address this Saab Underwater Systems is in the process of developing a hovering Hybrid AUV/ROV system to remotely perform IMR without or strongly reduced need for a supporting ship. This system is based on the Double Eagle SAROV, a hovering Hybrid AUV/ROV in production for the military market and proven components from Saab Seaeye ROV product range.
This paper will present the Seaeye Sabertooth offshore system, its concept of operation and design. It will also present our cooperation project (Saab and Aker Solutions) for this system.
Hot tapping of subsea pipelines is a cost effective method of transporting production fluids from satellite wells into existing pipelines. The process involves welding a branch connection onto a flowing operational pipeline and trepanning a coupon from the outside of the mother pipe. The technique is now well established and can minimise production down time. In most cases, the integrity of the branch weld is proven via subsequent pressure testing to prescribed limits based upon a multiple of the anticipated design pressure. However, in exceptional cases, such strength testing may not be possible. If this is the case it may be necessary to ensure the integrity of the welded joint by non destructive testing. This paper examines the use of non destructive testing and specifies the issues which need to be considered and the process involved in qualifying a Hot-tap weld. The use of NDT is justified by reference to the fracture toughness of the weld and associated microstructure and is based on a fracture mechanics argument. The paper draws on experience gained in the practical application of this methodology offshore.
Some years ago, a new methodology called automatic history matching was approached by the scientific community. The idea consisted in treating history matching as an optimization process, i.e. defining a cost function representative of the discrepancy between measured (real) and simulated data, and in minimizing the cost function. The minimization of the cost function can be obtained by applying a suitable optimization algorithm. Optimization and non-linear programming were not new methodologies in the field of applied mathematics. However, the selection of the most adequate optimization algorithm among those available in the technical literature is not trivial, and the number of independent variables involved in complex reservoir simulation does not make the solution of the optimization problem a standard procedure. In fact, the main criticalities of a history matching process change for each analyzed reservoir. As a consequence, the identification of an optimization methodology appropriate for a wide variety of reservoirs is quite impossible. Therefore, automatic history matching remains a dream and, more realistically, assisted history matching can be the target.
The concept of assisted history matching is that reservoir engineers are still in charge of reservoir model calibration, but they can rely on reliable optimization tools to better explore the parameter space and to speed up the convergence to one or more solutions.
The aim of this paper consists in discussing benefits, limitations and drawbacks of assisted history matching by applying new techniques, based on multi objective optimization and heuristic strategies. Attention is focused on the possibility offered by these methodologies of obtaining a number of calibrated reservoir models. Each of these models can then be used for field performance prediction so as to obtain a representative evaluation of the risks associated to any reservoir development scenario.
In 2010, the operator completed the successful replacement of a damaged fairlead within the mooring system of its FPSO (Floating Production, Storage and Offloading). This is believed to be the first time that a fairlead has been changed-out in situ on any floating installation in the North Sea. This was a complex operation involving many different vessels and topsides activities. This paper details how the damaged fairlead was safely secured and replaced.
The replaced fairlead was deemed irreparable because one of the axle retaining plates and its associated bolts were missing. However, after further ROV (Remotely Operated Vehicle) inspections, it was discovered that the remaining seven fairleads were also displaying symptoms of the same failure mode i.e. axle retaining bolts were missing or found loose placing further strain on the remaining bolts.
The condition of the axle retaining bolts was deteriorating and the operator was unsure when the next catastrophic failure could occur. Therefore, ROVs were used to secure the seven failreads as effectively as possible by replacing/ tightening bolts and air divers were mobilized to install pins to apply additional clamping
force while allowing access to the original retaining bolts. The original bolts were replaced and segregated so that they could be analysed onshore.
An investigation was undertaken to understand the failure mode of the FPSO fairleads. It was hoped to compare the differing levels of damage to different factors such as weather, mooring line catenaries, etc… to determine which factors are significant.
It was concluded that the bolt damage was mainly the result of design issues. A combination of QA/QC (quality assurance/ quality control) issues, environmental and operating conditions could explain the differing levels of fairlead damage.
The integrity of the mooring system was severely under threat throughout. Plus, replacing a fairlead is a long and costly exercise, therefore early identification of fairlead bolt issues and intervention is extremely valuable.
With increasing focus on the state of offshore installations as many approach and often exceed their original design life, there is a need for practical and cost effective methods to assess facility condition and assist operators and authorities in making decisions about the future investment / divestment of these assets. This paper presents one technique being developed and used by DNV for this requirement.
Normal asset integrity and condition assessments concentrate on work processes of the organisation which, though valuable, do not produce quantified results for decision making, or they concentrate on very detailed equipment assessment based on RCM or RBI techniques which can provide information, but take a long time to complete.
The technique outlined in this document provides an efficient methodology to develop a semi-quantitative result. This is sufficient in many cases to make the major decisions necessary to support Opex and Capex budgeting for continuing operations or to support the technical due diligence for change of operatorship in acquisition or divestment.
Using straightforward tools and principles, the paper leads through the top down approach covering: the consideration of current systems and their operational status; consequences of failure in terms of safety, production and environment, and how reliability and obsolescence are taken into account. Together these factors enable a risk ranking to be established which prioritises future budget and work requirements.
Inputs to the process are taken from a combination of historical operations and maintenance records, on-site examination of equipment and direct experiences of selected site personnel. Through these means, the technique combines a desk study with important buy-in of the local operations staff.
Samples of recent work in Africa and elsewhere will be demonstrated and refinements to the technique and other possible applications will be discussed.
Until now, one of the key players for the environmental regulations in the North Sea has been the Convention for the Protection of the North East Atlantic, OSPAR. But in 2008 the adoption of the Marine Strategy Framework Directive (MSFD) by the European Commission changed the deal. Although MSFD has more or less the same goal as OSPAR, it works differently and no doubt that its role will increase.
The paper, which complements two previous publications [Ref. 1 and Ref. 2], aims at clarifying the new role of both OSPAR and MSFD and developing the strategy recently adopted by OSPAR in September 2010 as well as the consequences of the MSFD. This latter requests that the member states (including Norway as the MSFD has an EEA effect) implement effective measures by 2016 at the latest. Both regulations aim at reaching a good environmental status (GES) of the maritime area by 2020. It may look as a long term, but it is not actually as it takes years to implement major changes in environment policy.
The paper explains in particular the current challenging change of perspective of OSPAR regarding the implementation of a risk based approach for the management of Produced Water - a formal measure being expected to be adopted by mid 2011 -, the threat caused by the OSPAR Recommendation on offshore chemicals to be substituted by 2017, and the significant threat that the MSFD poses on seismic activities, in relation with the definition of GES on energy introduced into the water, which is linked to underwater noise. But it also develops a few other issues, less publicized (NORMs, the DRILLEX initiative, etc.).
The potential impact of the measures to come may be huge (previous OSPAR measure on Produced Water cost a billion pounds to the North Sea Offshore industry) and it is important that the industry takes a role in the discussions to come.
Assessing reservoir connectivity during the earliest stages of reservoir evaluation is highly desirable for successful field development. Nevertheless, it has long been problematic to assess reservoir connectivity prior to production. Recently, downhole fluid analysis has enabled facile assessment of fluid compositional gradients vertically and latterally. Using equations of state, the extent of fluid compositional equilibrium can be established. Only a process that stretches across the entire age of the reservoir is likely to capture geologic events that cause compartmentalization. Fluid composition equilibration requires mixing of the entire content of the reservoir which occurs only on the geologic time scale. Restrictive flow barriers are not compatible with thorough mixing of fluids throughout the reservoir. Fluid composition equilibration provides a tight constraint to test connectivity.
In this paper, the time constants for fluid composition equilibration are evaluated in numerical simulations. Equilibration processes are simulated in a simplified model over geologic timescales at isothermal conditions where diffusion and gravity are the active mechanisms. A variety of initial conditions and reservoir fluid types are considered. The effect of barriers on the equilibration time is investigated for single and multiple barriers. The results are compared with analytical calculations. Longer equilibration times correspond to tighter constraints on connectivity.
This work shows the progression of compositional gradients over geologic time until all components have reached zero mass flux. It investigates the foundation of connectivity studies that rely on fluid composition.
Determination of fluid equilibrium should become part of the standard procedure for reservoir connectivity evaluation.
A compartment is a part of a reservoir that needs to be penetrated by a well to be drained. Undetected flow barriers may lead to disappointing production results. Establishing reservoir connectivity prior to production is highly desirable.
Identifying compartments is not very difficult. The use of wireline formation testers to acquire static formation pressure surveys is common practice. The word static refers to pressure gradient analysis in single or in multiple wells prior to production at virgin conditions. Even subtle discontinuities and differences in pressure gradients can indicate reservoir compartmentalization (Canas et al. 2008; Elshahawi et al. 2005; Jackson et al. 2007).