The purpose of reservoir modeling is not only to build a model that is consistent with currently available data, but also to build one that gives a good prediction of its future behaviour. Updating a reservoir model to behave as closely as possible to the real reservoir is called history matching, and the estimation of reservoir properties using this method is known as parameter estimation and it is an inversion process.
Here we apply one of the evolutionary algorithms (Particle Swarm Optimization - PSO) to estimate porosity and permeability using both production and 4D seismic data. PSO is a population-based stochastic optimization algorithm. It is known as a swarm intelligence algorithm because it was originally inspired by simulations of the social behaviour of a flock of birds. The method combines simplicity in implementation and high capability for distributed (parallel) computing.
The results obtained on a 2D section of the Norne Field in the Norwegian Sea, demonstrate that this parameter estimation approach combines moderate computational requirements and better objective function values and exhibits good ability to handle history matching problems without exhaustive sampling of parameter space.
This paper provides operators of up-stream oil and gas assets an over view of some of the lessons leant from a range of retrospective full Hazard and operability studies (HAZOPs).
The Baker report into the Texas City incident highlighted the need for robust Process Hazard Analysis. This strengthened an already growing understanding for the need to re-validate the hazard identification for existing assets. HAZOP is recognized as a systematic methodology for the identification and initial assessment of process hazards. As a result full retrospective HAZOPs have now been undertaken for a number of upstream oil and gas facilities over the past few years. This paper aims to share the learning from these retrospective HAZOPs of existing installations. Key areas are a) How to do it better: taking into consideration that HAZOP fits into a wider Process Safety Structure, need for plant /process experience, preparation and the raising of recommendations/actions, close out of recommendations/actions, etc and b) Some common themes identified from the HAZOP exercise: such as with, losses in knowledge, flare systems, Level instrumentation, Drainage/effluent systems, utility systems, methanol systems, redundant equipment, MOC failures, reliance on operators and procedure failures, aging equipment (isolation).
This paper also details potential ‘what next' for PHA Hazard identification, as the effort and commitment to periodic full retrospective HAZOPs is considerable. However, the consequences for organizations in not remaining vigilant on changes to their asset Hazards can be significant.
Enhanced oil recovery methods for heavy oil are growing at a fast pace. In Canada alone, approximately 53% of the nation's crude oil production (~2.8 MMBbl/day) comes from Alberta's Oil Sands. Remote sensing and monitoring technologies developed for thermal methods are providing the industry with an immense amount of data that will aid in the improvement and optimization of production performance. This paper details how to integrate seismic, tiltmeter, temperature observation well data with field production data, first with simple surveillance techniques, then with flow simulation. Currently, heavy oil is experiencing significant growth in reserves whereas conventional light oil reserves are essentially fully tapped and are diminishing. Heavy oil is becoming key to meeting growing energy demands worldwide.
Current analytical approaches to heavy oil reservoir studies are too general, and tend to not include rich surveillance data such as seismic, temperature and pressure. This general approach over-simplifies the dynamics present in these reservoirs and does not give an accurate depiction of behavior and performance estimation. On the other hand large simulation studies can be cumbersome and not adaptive to new surveillance data. This paper focuses on a hybrid approach to analyzing various heavy oil fields in Canada, and outlines newly developed surveillance methods which better characterize heavy oil reservoirs.
These field cases include geological data, pressure readings, seismic analysis, temperature observations, and historical production, all of which are used to enable the optimization of field production.
The proposed analytical techniques allow for a more precise estimate of recovery and sweep efficiency so that an efficient optimization strategy can be developed. Applying these analytical techniques to the Surmont and Christina Lake projects in the Athabasca area has given particularly important insight into SAGD steam chamber development and has shown to accurately estimate steam chamber volume and shape.
When seismic and temperature data is used to estimate steam chamber volume there is strong correlation to produced volumes and shows that displacement efficiency is a time dependant variable and increases with steam chamber maturity, initially ranging only 20-30% and approaches 60-70% with time. These results also indicate that effective drainage of established steam chamber volumes takes about 2-4 years.
Displacement efficiency has shown to be a critical factor in controlling recovery from the steam chamber and although increased volumetric sweep is beneficial, this paper has shown that the rate at which it grows greatly affects the rate at which the displacement efficiency increases in the steam chamber. Increasing the volume of the steam chamber too quickly can potentially decrease the effectiveness of SAGD because it tends to introduce many unstable chamber characteristics and develop new significant heat losses.
Simulation has shown that heterogeneity can in fact aid in the SAGD process but controlling steam chamber uniformity and development in heterogeneous reservoirs becomes much more difficult. The vertical barriers, if monitored closely, can help in dampening the rate of steam chamber growth ensuring that residual oil saturation in the established chamber volume is at its lowest before new energy routes are introduced.
Duty holders and operators of major hazard assets should have in place the required processes, programmes and procedures which coherently:
This paper describes how, collectively, these processes, programmes and procedures are aligned to a major accident prevention process which is a core element in the management of an asset at all stages of its life cycle.
The primary goal is to ensure that plant and equipment does not, and is not allowed to fail in such a way as to cause or substantially contribute to a major accident.
The requirement to manage assets throughout their life including any life extension period should be mandated by company policy and standards which in ConocoPhillips case recognises the design, operation and maintenance of an asset should be such that its integrity is preserved at an acceptable level of risk throughout its operating life.
Asset life extension is a process that begins when an asset's components wear out, requiring maintenance or repair to maintain a satisfactory operating condition. This begins soon after the asset enters operation for the first time and continues throughout the life of an asset.
However, with increasing age, unchecked asset degradation can become widespread and gradually escalate to a point where significant restoration is required. Consequently, major accident risks may be increased requiring an asset operator's management system to be carefully designed to contain them.
By embedding the Major Accident Prevention Process in the way we design and manage our assets, we ensure that asset integrity is a continuous and forward looking process that supports the case for asset life extension.
The definition of asset integrity used in this paper is; the design, operation and maintenance of an asset so that its integrity is preserved at an acceptable level of risk throughout its operating life.
This statement takes a long term view of an asset's life and does not limit this to the original period for which an asset may be required to operate, but incorporates extension of asset life beyond this period. This paper is written in the context of fixed physical assets involved in the production, processing and delivery of hydrocarbons. There is an offshore emphasis, but the principles also apply to major hazard assets offshore and onshore.
Implicit in this definition is the achievement of major accident prevention.
Various major incidents have shaped different countries' regulatory approach to major hazard industries. For example, the Piper Alpha tragedy led to an overhaul of the UK regulatory framework governing offshore safety. The body of legislation issued during the decade following that incident led to a safety regime, the central pillar of which is the Safety Case Regulations. The emphasis of these regulations is on hazards and risks management - in other words; major accident prevention.
Berg, Eirik A. (Statoil ASA) | Reksten, Kari (Statoil ASA) | Scott, Anthony Stephen John (Statoil) | Ibatullin, Tair (Statoil ASA) | Møllerstad, Hilde (Statoil) | Aasum, Yngve (Statoil ASA) | Julseth, Lillian (AGR Petroleum Services)
The Mariner field - license 9/11 in the UK - was discovered in 1981 and is situated on the East Shetland platform. Mariner consists of two tertiary reservoir intervals of unconsolidated sand at depths between 1200 and 1500 mMSL. The deeper Maureen reservoir consists of stacked non-channelized sheet-like sand lobes deposited in a shelf to slope setting. The Maureen oil water contact (OWC) is stepping considerably and is shallower to the west. The Heimdal reservoir consists of deep-marine slope-channel sands within the mudstone-rich Lista interval, ranging in thickness from a few meters up to 40 m. The reservoir is heavily remobilised. The Heimdal OWC is uncertain with variable ODT (Oil Down To) observations and anticipated perched water. The total Mariner oil reserves are estimated to app. 400 MMBO (Million Barrels). The Maureen reservoir has 67 cp oil (14oAPI) in a 0-40 m oil column and a large bottom aquifer. The Heimdal reservoir contains two thirds of the reserves and has 508 cp oil (12 API).
Steady State SCAL studies indicate that Krw may be viscosity dependent. The Heimdal reservoir is planned to be developed using an inverted 9-spot well pattern due to uncertainty in mapping of the reservoir. The Maureen reservoir will be developed with horizontal wells. As the recovery factors are only 22%, Enhanced Oil Recovery using polymer is investigated as an upside to be matured towards production start. IOR through use of down-hole inflow control devises is progressed in a technical qualification program. OBC (Ocean Bottom Cable) data will be acquired to improve the mapping of the Heimdal reservoir.
Pigging of pipelines within the oil industry has been around for well over 100 years and has been used as the preferred (if not the only) internal method for cleaning, maintaining operational efficiency, data gathering and inspection for integrity management purposes.
The benefits in carrying out routine "operational?? pigging cannot be underestimated and operational pigging to remove water, wax, scale and other debris which is formed during routine operations whilst transporting crude oil and gas is paramount in maintaining the integrity of any crude oil and gas pipeline system. The build up of such debris is common whether the pipeline is offshore between production platforms, from a production platform to onshore or a totally land based pipeline.
Similar problems are encountered to varying degrees dependent on pipeline size, location and type of the crude product being transported.
Pipelines are normally designed for a specific maximum flowrate, this maximum rate is generally maintained on a "plateau?? for several years of a field's life, during which routine pigging operation presents little or no real problem to the pipeline operator. The cleaning pigs which are used are generally designed for the "maximum?? of "potential flowrate?? which the pipeline is due to see during it's plateau phase of operation. This assumption, that these pigs will be suitable for the life of field operations, is common place with pipeline operators and as such there is a significant increase in the risk that pigs will become "stalled?? on a regular basis or potentially "stuck?? causing significant disruption to operation, production and in the worst case scenario a very costly subsea intervention. As can be seen from Industry Analysts¹ there will be a decline in overall oil production not just from the UK Sector but from the North Sea Basin and Europe as a whole. Therefore the need to understand pigging operations in "low flow?? modes of operation cannot be stressed highly enough.
With most of the world's largest and easiest-to-exploit deepwater oil reservoirs already under development or producing, the industry is now facing new deep offshore challenges: the production of smaller fields that often contain more difficult oils.
The tie-back of new fields to existing facilities can be a viable method for developing such marginal offshore fields, which are often too small to be developed economically on their own.
The use of subsea processing and innovative field architectures as development solutions is fast becoming a reality. Such challenges are already being addressed in the development of certain fields in the Gulf of Mexico (King, Perdido...), Brazil (Marlim, BC- 10…) and the Gulf of Guinea (Pazflor). However, long subsea tie-backs come with inherent complications.
The most demanding are the flow assurance issues arising from the different operating regimes, and these may be combined with more viscous fluids and/or reservoirs at low pressure or low temperature.
This paper examines the advantages and limitations of various field architectures that may be considered for long satellite tie-back lengths in deep waters.
The first part addresses production considerations such as turndown, preservation and restart management for each candidate architecture. The impact of tie-back length on operating modes is also evaluated. The second part examines the impact of these operating modes on the receiving facilities.
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.
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.
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.