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.
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.
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.
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.
The US presidential commission's "Deep Water?? report inquiring into the causes of a recent Gulf of Mexico accident recommends an independent industry-run safety organization along the lines of the nuclear and the chemicals industry for the US offshore industries. The report in reference to essential features of this "self-policing?? organization states:
"The main goal is to drive continuous improvement in every company's standards and performance, measured against global benchmarks?? and
"The industry needs to benchmark safety and environmental practice rules against recognized global best practices.??
CCPS has published recommended lagging and leading indicators of Process Safety performance which enable companies to track and monitor their efforts. Lagging indicators help companies compare their process safety performance in regard to incident frequency and severity, i.e. tier 1 and 2 events. Comparison of leading indicators level, i.e. tier 3 and 4 activities, isn't possible without establishing a deeper understanding of the management decision process. Tier 1 and 2 data is relatively easy to obtain but there is currently no way for companies to formally compare how their respective tier 3 and 4 practices affect either the consequences or the severity of the outcome.
Formal benchmarking provides an opportunity for companies to identify gaps in their current practices so that they can work towards continuous improvement. By sharing their data they help create a better understanding of industry best practices that then become global benchmarks for others to emulate. The paper details salient aspects of a process safety benchmarking initiative recently developed in conjunction with CCPS that considers performance on six of the twenty Risk-Based Process Safety elements. The paper briefly describes how the program was developed and provides new insights into HSE management. Later, it illustrates how the upstream industry can learn from the downstream industry.
PAST SAFETY RESULTS AS A PREDICTOR OF FUTURE SAFETY PERFORMANCE
Traditionally, organizations have used different metrics to measure their safety performance. The underlying principle being "you can't improve something you do not measure.??
However, when it comes to measuring safety performance you are also limited by the means and methods of your measurements. A high bias towards lagging indicators creates a system that is mostly reactive—leaving you the option to learn from your mistakes only after they have happened.
In addition, many companies tout "Zero Incidents?? as their safety goal. And in doing so often set themselves up for shorter limited gains at the potential cost of future much larger losses. When the focus shifts to zero incidents, the things that are of immediate consequence often take precedence over things that can wait, especially in a resource constrained environment. As a result, low consequence yet high frequency events take up more of management and line attention than high consequence yet low frequency events.
Eventually, a good score on these occupational/ personnel safety area leads everyone to believe that things are going just fine. Till something terribly goes wrong. Just as it did for a Texas City refinery that had two-third lower LTIR historical record than the industry averages. And then an explosion killed 15 people in a single incident.
Mengkapan is a mature offshore oil field in the Malacca Strait PSC, located in central Sumatra, Indonesia. First oil flowed in 1986. The production wells produce multiple sands commingled with simple ESP completions. Cumulative oil production at the end of 2010 was 35 MMSTB, and the current recovery factor is around 50%.
Over the years, as oil rates declined and water cuts increased, the team ran production log campaigns to monitor the oil rate and water cut of sand. These logs revealed the occurrence of cross-flow and oil-blocking, which was attributed to differences in permeability and pressure between the sands. The log results led to workovers to isolate high water-cut sands by setting production packers. But after more years passed, the point was reached where there were no more zones to isolate with packers, and the team was forced to consider well abandonment.
Rather than abandonment, the team changed their mindset from "there is no remaining oil" to "there is by-passed oil and we can get it". The chosen technique was to squeeze-cement high water-cut zones and re-perforate by-passed oil sands identified from cased-hole logs.
In ME-02, massive cross-flow between high-permeability sands seen in the production logs did not matter, because the suspected by-passed oil sands were the lower permeability sands at the top of the perforated intervals which were unaffected by cross-flow. The Carbon-Oxygen log suggested by-passed oil in the upper part of some sands. Next, all perforated intervals were squeeze-cemented, using a technique fine-tuned with the team's knowledge of cross-flow. Then, the by-passed oil zones were re-perforated, and the well was completed and put on-line.
Prior to squeeze cementing and re-perforation, ME-02 well produced 9000 BFPD, 45 BOPD. After the workover, the well produced 2000 BFPD, 104 BOPD. The budget was USD 660,644.00, but only 60% of the budget was used. It paid out in two months.
This paper tells the failures by relying on a single tool and the success story in ME-02 to increase the value of a workover (reduced operation cost and increased oil gain), including the concept, the data gathering, and the field operation.
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.
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.
Nozzle/orifice, tube, and helix Inflow Control Devices (ICDs) have been tested for flow performance at the Statoil multiphase flow loop facility in Porsgrunn, Norway. The test results are given as performance curves for single phase oil, water and gas. Two phase tests have also been run for oil/water and oil/gas. Results confirm that single phase ICD flow performance characteristics can be accurately described with a physical model, and corrected by an error function which is predominately dependent on the Reynolds Number. For the fluids tested, the gas and water cut multi-phase data exhibits reasonable correlation to the single phase loss coefficient values for nozzle/orifices, water cut only for tube ICDs, and does not exhibit correlation to the water or gas cut multi-phase loss coefficient values for helix designs, especially at higher choke settings.