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Fractured basement - Hurricane's experiences in the Lancaster field

Thursday, August 9, 2018

Hurricane Energy has drilled 2 horizontal wells in the Lancaster fractured basement field, West of the Shetland Islands, North of Scotland, and expects them to produce a total of 20,000 bopd based on well test results.

Hurricane Energy, an oil and gas company based in Surrey, UK, has drilled 2 horizontal wells in the Lancaster fractured basement field, West of Shetland Islands, North of Scotland. It has drilled a total of five wells on the Lancaster field. Based on well test results, it expects the two horizontal wells to produce 20,000 bopd in total, when the field comes into production in early 2019.

Fractured reservoirs have not been given much attention in the UK until now - partly because of the abundant sandstone reservoir horizons, but also because until the mid-1990s there was insufficient technology to confidently exploit fractured basement reservoirs.

Robert Trice, CEO Hurricane Energy, explained the company's work at the Finding Petroleum London forum on Jan 23 2018, 'Understanding Fractured Reservoirs'.

Geological background

Basement rock is defined as rock which is not from any kind of sediment, i.e. which formed from when the earth was a burning ball of magma and cooled down, 2.5 billion years ago. The initial joints (cracks) in the rock appeared from the initial cooling.

Then the basement below Lancaster was repeatedly buried under more layers of rock, and uplifted, over a long period of geological time. During this period of geological time the basement rock and the associated fractures was subject to periods of flushing by hot and cold water which would have deposited and removed minerals.

Planning the second well

The focus of the talk was on how Hurricane aimed to get a better understanding of the fractures and faults, before drilling its second horizontal well, '7z'.

The 7z well was planned to be drilled to the north of the first '6' horizontal well, aiming to penetrate a series of 'seismic scale' faults (large enough to show on seismic). It was expected to drill through reservoirs of average porosities of 3.6 to 4.4 per cent. It was expected to repeat the success of the first horizontal well, with flow rates of around 9,800 and similar API of oil. It did turn out to be a good well, as explained later.

But in order to put the drilling plan together, 'we had to be confident we felt we understood what was making the reservoir work,' Dr Trice said. In other words, the company needed a working reservoir model.

Pressures and drilling

Understanding the subsurface fluid pressures is very important. For drilling, it is important for safety and managing drilling muds, ensuring the drilling mud pushing into the reservoir has a higher pressure than oil pushing out into the well. The fluid pressure also controls how liquids will flow into the well. Fractured reservoirs can show a variety of aerial pressure regimes if associated with pressure sealing faults

The first vertical well was drilled on the assumption that the pressure increase to the subsurface would be hydrostatic, i.e. the same increase in pressure as you would see with a vertical column of fluid, caused by gravity force of the fluids above. This assumption was based on data from other wells in the region, and the geological model.

For the first well, the company was concerned about the drilling mud being lost into the fractures, so it used a 'shear splitting' mud called DRILPLEX, which is designed to block up fractures. The disadvantage of this mud is that by blocking up the fractures, it makes it hard to do well tests or logs.

The results of well logs showed no signs of overpressure in either the basement or overlying clastic rock. 'That gave us real confidence in the mud weight and the pressure gradient,' he said.

Using this understanding, the second vertical basement well '4Z' was drilled using an experimental tool which made it possible to drill 'balanced' rather than 'overbalanced' (i.e. with the weight of the mud exerting a greater force pushing reservoir fluids back into the reservoir, than reservoir forces pushing on the well to get out).

The drilling was done with a mud with no particulates in it. This has the benefit (from a logging point of view) that it does not build up a 'mud cake' along the well wall. It is basically salty water (a brine). Brine proves 'fantastic for data acquisition' but can make it tricky getting tools to the bottom of the hole due to the brines poor lifting capacity resulting in drilling cuttings collecting at the bottom of the borehole

For subsequent drilling, Hurricane anticipates that there will be a normal hydrostatic pressure regime in the reservoir, but no extra 'oomph' from overpressure carrying fluids into the well, he said.

Stress models

Understanding the stresses and stress direction was considered important in understanding the fractures. Before drilling, there was a theory was that fractures aligned with the stress direction are going to produce more oil.

However studies made after drilling did not support that idea. 'Fractures of a variety of orientations flow,' he said. 'Some of these large aperture fractures which flow have a different orientation.'

The indications are that the maximum horizontal stress in the reservoir is NE SW orientated, based on borehole breakout data (analysing the direction where the borehole is breaking into smaller pieces horizontally during drilling).

Schlumberger was contracted to develop a number of stress models, making a map of joints (gaps in the rock layers) which it could see on imaging logs (digital images taken down hole), and showing how they were orientated. It concluded that again the maximum horizontal stress is NE SW direction.

Dr Trice explained that Hurricane has no definitive stress model for the reservoir but has a working model which it is currently challenging with recently acquired data.

Modelling fractures, faults and joints

The fractures, faults and joints in Lancaster occur at a number of scales. There are micro fractures, defined as having a trace length less than the diameter of the bore hole, and joints classified from borehole imaging as fractures with a trace length at least as long as the borehole diameter.. Then there is large 'seismic scale' faulting, discernible from seismic. Between the two there are characteristics of the fracture system which can be discerned from dynamic well testing, Dr Trice said.

Large scale faults are an important target for exploration appraisal and development. The company wanted to be confident in its fault maps.

The first well was based on a very low density fault map. But this map became richer as work progressed. 'I asked my geophysicist to create a map which 10 geophysicists would agree with. In other words, every fault on there really had to be there. We could potentially drill a well through it.'

'As we add more data and integrated it, the fault pattern became more confident,' he said.

Data gathered during the drilling, and in subsequent well logs, was also used to further develop the fault map.

Both the seismic and the horizontal well logging indicated that the faults are predominantly subvertical (close to vertical).

A map was also made of the joints within the reservoir. The joint classification can be made in a number of ways, such as the orientation (going NE SW), cross joints, orientation at high and low angle, and large aperture joints (over 2cm). A greater than 2cm aperture is the size associated with turbulent flow, and also Karst type reservoirs.

The study showed that there was not any increase in the number of joints when close to faults, or within 'fault zones', as some studies of fractured reservoirs elsewhere show.

The bulk porosity (void fraction) is about 4 per cent. Bulk porosity is interpreted as being related to fractures and includes fractures enhanced by dissolving (dissolution) of the rock,

Log studies

Well logs were widely used to get a better understanding of the fractures, faults and joints. It helped that the company's CEO, Robert Trice, had a background as a petrophysics, so had a great deal of experience working with well logs to 'constrain' or understand the limits of what might be happening.

The most important data proved to be the PLT (production logging tool), which can provide information about the formation fluids.

The data can be integrated with high resolution gas chromatography (analysing gas samples for their content). It gives further information about the permeability and fluid types.

The company also took sidewall cores (rock samples taken from the side of the well bore) while drilling. Before taking the cores, it used digital imagery (known as 'digital image logs') to identify a good place in the sidewall to take the core, and make sure it was not trying to take a core from within a joint.

The position and depth of a given sidewall core is established by running an UBI (ultrasonic borehole imager). Petrophysical analysis is undertaken on the laboratory on the SWC's.

With well logs it as possible to confirm the presence of fairly large aperture fractures, for example one with 40cm diameter, flowing oil. 'These things are quite common in the basement and indicates there's something helping the fracture system other than mechanical failure,' he said.

Another useful piece of evidence about fracture size was from rock samples which came to the surface stuck to the drillbit. Dr Trice showed one photograph of a rock sample, which looked like a cobble from a beach, worn down by water. It had been choked in a fracture, and indicates that the fracture aperture must have been wide e enough to hold it.

Micro fractures can be clearly seen on the image logs, and by analysing them when 'captured' by SWC's itis possible to understand the diagenetic processes (how the rock was formed) through thin section analysis

The NMR (nuclear magnetic resonance) log can be used to get porosity data.

Putting into a model

All of the fracture, fault and joint data was put together in a model, which could then be used in a reservoir simulator, to see how fluids might flow, and then used to plan the drilling path.

Consultancy Golder and Associates was brought in to put together a discrete fracture network (DFN) model, by consultancy Golder and Associates.

The model was run in a flow simulator, which showed that the 'regional joints and faults are the main contributors to the flow from the fracture system,' he said.

Drilling 7z well

The 7z horizontal well was drilled based on this fracture network model and the interpreted seismic,

Based on the model and simulation, the well was expecting to encounter 11 fault zones, and produce at a similar rate to the 6 well, perhaps higher rates.

As the well was drilled horizontally through the faults, the path dropped, finishing up 70m below the start point vertically.

The average fault zone width for this well was 49m, just above the 40m average for the field. Porosities for the reservoir was 3.8 per cent, slightly lower than the field average of 4 per cent. The regional joints ran NE SW, supporting the reservoir model.

'From the drilling data, it looks like we've got a nice reservoir,' he said.

Ultimately the well flowed at 15,000 bopd in the well test, with flows limited by surface equipment, and with a high productivity index (a measure of how easily fluids flow into the well).

'So, a very favourable well. The well was suspended as a future producer,' he said.

Future development

Hurricane now plans to tie the 2 horizontal wells to an FPSO (a floating production storage and offloading vessel). It aims to keep production levels from both wells at 20,000 bopd, to avoid reservoir damage. Over the first 6 years it expects to produce 37m barrels.

It plans to do interference tests on the wells to try to better understand the dynamic properties of the reservoir.

After that, it will be able to plan a second phase of field development, with more wells, and wells further away.

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