Carbonate evolution

Analysis figures from Schlumberger estimate that 60% of the world’s remaining oil, and 40% of its gas reserves are held in carbonate fields.

Indeed, its no exaggeration to say that these reserves present the industry with some of the greatest challenges and opportunities to develop new technologies and processes to tackle the need for ever more energy.

Last year’s BP Statistical Review estimated the Middle East plays host to 62% of the world’s proved conventional oil reserves, of which more than 70% of these are held in carbonate reservoirs.

To meet rising global energy demand and consumption, sustaining production from existing fields and increasing recovery factors will be critical. To do this, it will be necessary to improve our understanding of fluid flow mechanisms and reservoir systems.

Spearheading Schlumberger’s efforts in this field is Dubai-based Bernard Montaron, theme director for carbonates and naturally fractured reservoirs.

“Several years ago Schlumberger decided to assign theme directors entirely dedicated to work on a small number of business themes. Heavy oil, deep water, and carbonates are example of such focused themes,” explains Montaron.

“My main mission is to facilitate the integration of Schlumberger technologies and expertise from all business segments across the entire organisation to address specific challenges and market needs in my business themes.”

Montaron’s role is geared around understanding technical challenges that oil and gas companies need to address today and in the future regarding carbonate reservoirs and naturally fractured reservoirs. “The role is a world-wide position, but given that the Middle East is the centre of gravity for carbonates on the planet, it makes perfect sense to be here in Dubai.”

Carbonates in the Middle East

The overwhelming majority of Middle East proven oil reserves are in carbonate reservoirs, as well as 90% of its gas. The statistics are slightly skewed by the sheer size of some of the fields found here.

“The largest gas reservoir on the planet is here, between Iran and Qatar (South Pars and North Field respectively). That single field holds close to 30% of all gas reserves known in the world today,” says Montaron.

For oil, the reason the figure is slightly lower is because there are extremely large sandstone reservoirs on the Arabian Peninsula. The Burgan Field in Kuwait is among the largest sandstone reservoirs in the world, as is the Safaniya field in Saudi Arabia. Ghawar is the world’s largest onshore field, covering a vast land area of around 280 x 26 kilometres, and it’s a carbonate reservoir.

The concentration of hydrocarbons in and around the Gulf countries is often attributed to geographical serendipity, but the formation of carbonate hydrocarbon fields in the region can be credited to atmospheric conditions, which make the formation of carbonates a near certainty.

“In this region carbonate hydrocarbons have been typically formed by the precipitation of calcium carbonate from seawater. To reach a stage where the calcium carbonates form, the sea water has to be evaporated, so the high temperatures and coastal winds create the ideal elements needed,” says Montaron.

As water is removed by the heat from the sun and by wind, the concentration of minerals increases. As the carbonates are formed, the remains of marine life are trapped, such as shrimps, fish and crabs. These layers of trapped carbon grow at a rate of around half a millimetre per year in regional conditions.

This doesn’t sound like much, but over 2 million years that accumulates to 1 kilometre of carbonates,” says Montaron. The weight of those carbonates force it deeper and deeper, to hotter parts of the earth’s crust, where it gets cooked, and oil is formed.

“Basically, in this part of the world the atmospheric conditions are ideal for carbonate formation, the heat encourages a huge amount of evaporation, and there’s a lot of marine life and corals that adds carbon matter.”

Whilst the geological birth of the region’s oil may seem an impossibly distant point in history, the creation of carbonate deposits is still being played out in the Gulf before our eyes today. “In Abu Dhabi you can visit geological sites where carbonates are being created right now. Carbonates are formed in shallow seawater by several natural mechanisms, and there are some excellent fields where you can see the initial deposits being created.”

The other interesting thing about calcium carbonates is that it’s nature’s own way of removing carbon dioxide (CO2) from the atmosphere. “The CO2 gets dissolved in the seawater and is trapped in the carbonates, so the biggest CO2 store on the planet is in the carbonates and carbonate reservoirs.”

Carbonate structures tend to pose more complex problems for the oil industry because it forms a very brittle rock that tends to crack under tectonic pressure. This cracking creates fractures and corridors that pose significant challenges to drillers, seismologists and geophysicists, as pinpointing their exact location is exceptionally difficult.

The challenges

One of the major problems with carbonate reservoirs is the lack of accurate data on production available in the public domain. Most of the time oil and gas companies consider these statistics very sensitive figures. What we do know, from reputed sources, is that the overall average recovery factor is around 35% overall for sandstone and carbonate reservoirs. It’s also fairly certain that the recovery factor, on average, is lower for carbonates.

“There are many reasons behind why recovery is trickier in carbonate reservoirs, but heterogeneity is the principal problem,” explains Montaron. The rocks tend to be a lot more heterogeneous than in sandstone.

Sand that follows a 100km journey from weathered rock or mountain, and is then eroded along wadi’s or river beds, is then rolled by the sea, has a very homogenous character. With carbonates, they form in a much more irregular pattern along the coast, and so as the formation gets deeper, there is much greater deviation.”

These deviations can be caused by a myriad of factors. Crabs may dig holes in the carbonate in one place, whereas a couple of hundred metres away a mangrove might form which is laying down vegetative matter, but leaving traces of root networks in the rocks.

Over time these will form very different structures. Added to this, when you are three kilometres deep, some of this translates into vugs, which are small cavities in a rock or vein, often with a mineral lining of different composition from that of the surrounding rock, which complicates the picture further.

On top of all these factors impacting the carbonate structures is the issue of tectonic activity. “When the plates beneath us move they tend to buckle, bend or crack under the huge pressure.

This forms fractures and these structures can have a huge impact on the recovery factors. When seawater is injected to push the oil towards the production well, under natural pressure it may go into these cracks and get directed away from the matrix or body of oil you are targeting.”

Heterogeneity is the number one challenge when dealing with carbonate reservoirs. The secret to maximising production in these fields lies with accurately mastering the reservoir description.

“Being able to locate where those big fractures are, knowing how the different rock types are distributing the reservoir, and from that being able to create a complete description of the permeability of the reservoir is making a step in the right direction.”

Ultimately, if this can be achieved, then placing the wells and pinpointing where to inject water or gas will have a potentially massive impact on the production yield.

Field evaluation

A reservoir may be 30 km East – West and 50 km North – South, and maybe 1 kilometre deep. When you are looking at a field on this scale its vital to understand how the fluids are going to move within it.

“A good analogy is to imagine the reservoir as a roadmap of a country, and understanding the vehicular traffic through it,” says Montaron. “For example, throughout a country there will be lots of small roads running all over, but that’s not an efficient means of getting around. If any significant distance is going to be covered, then highways are the quicker routes.

Just like a road map, within the matrix of the carbonate reservoir are fractures, which act as highways. Most of the movement happens along these fracture corridors formed by tectonic activity. Some of these major arteries could be 10 metres wide, three kilometres long, and if fracture corridors can be found and tapped, then you hit these highway for fluids.”

When drilling, if by sheer luck, the vertical well hits the fracture corridor then you have an area where permeability and the flow of oil from all the surrounding cracks will migrate – essentially taking advantage of a giant natural feature of the reservoir to drain all of the oil towards the well.

“However, if you drill just a hundred metres away you could be in a very tight matrix of the reservoir, and the productivity of the well could be 50 times less that the one that struck a fracture corridor. Of course, it could still produce 2000 bpd, but if you found the natural highway for the oil, it would be more like 20 000 bpd.”

In carbonate reservoirs it can be quite common that out of 25 wells drilled, just one of those may produce 60% of the total yield, and this is an illustration of the difference striking a corridor could make.

“Of course, on the other hand, it could also happen that the fracture corridor is connected to water, in which case your well will produce and recycle a lot of water, which is far from ideal, so understanding which fluids these structures will bring to your wells is essential.”

Knowing that the fracture corridors act as conduits for oil or water is just the first step. The major problem is that in the scheme of an oilfield seismic report, these fractures are very difficult, almost invisible to see on seismic images.

Understanding the big structures and taking advantage of high-resolution seismic imaging, and new workflows to characterise the reservoir is a fundamental step towards improving recovery yields.

“It’s only very recently with seismic we’ve been able to see these fracture corridors. The seismic signature is very small, and they are easily confused with noise. To get a picture of these structures you can’t filter anything out of the pictures; you want all the noise and a very smart way of pinpointing these hard to see structures.

Fracture corridors are impossible to see with the naked eye and even the best seismologists will only be able to see the folds above, but the corridors remain near invisible.

“Smart processing of high resolution seismic – a new workflow called FCM for fracture cluster mapping – will show you these structures, but you need to understand each rock layer within the reservoir. Comprehensive, detailed reservoir characterisation is the answer. Having a complete picture of what you’re dealing with is absolutely crucial.”

This is achieved through full data integration. Seismic will give you an image of the big and interesting structural features, but then you have several other tools such as wireline data logging.

Precision monitoring of the downhole conditions is the best way of understanding the rock types and the drilling environment.

An example of this data integration is available through WesternGeco’s Q-Technology surveys. “Each survey is a unique combination of acquisition, processing, and inversion technologies required to produce solutions to reservoir problems, whether defining reservoir geometry, characterising reservoir properties, or monitoring fluid movements. Acquiring the right survey the first time increases its value as a reservoir-management tool at every subsequent stage in the field’s life.”

These technologies are rather more advanced than standard seismic surveillance methods because they record the data from individual seismic detectors without summation.

The seismic wavelet is controlled through source signature monitoring. Together, this results in the highest quality seismic fidelity and the maximum suppression of noise. Hence, subsequent Well-Driven Seismic processes such as well calibration, inversion, and classification techniques all produce more accurate results.

“Using this sort of technology enables incredibly powerful data analysis which in turn generates resolution that could not be generated by more traditional bundled seismic systems,” says Montaron.

A new workflow has been developed by Schlumberger to improve fracture characterization and to effectively model carbonate reservoirs. The FCM Fracture Cluster Mapping workflow integrates Q-Technology services, borehole measurements and Petrel seismic-to-simulation software with expert interpretation and flexible work processes, resulting in improved production performance.

The workflow helps production engineers make better decisions for the location of injectors and producers, plan well trajectories, improve production predictions and form a comprehensive Discrete Fracture Network (DFN) model.

It makes a clear distinction between diffuse fractures that can be modeled using geo-statistical techniques, and fracture corridor ‘highways’ that must be detected and placed in the reservoir model at their exact field location.

This year Schlumberger introduced Carbonate Advisor petrophysics and productivity analysis service. Carbonate Advisor offers a systematic analytical framework to efficiently deliver a timely, comprehensive petrophysical evaluation of carbonate rocks.

This integrates information from magnetic resonance and elemental capture spectroscopy, as well as other logs and core data, to produce a single, complete formation evaluation of carbonate reservoirs.

Carbonates and enhanced oil recovery

Most of the data available from pilot tests worldwide, stretching back over the last three decades reveals very few EOR pilot studies have been in carbonates. “The established methods of EOR, such as polymer or surfactant injection work very well with sandstone reservoirs because these chemicals are employed very efficiently when pushing the oil out because the oil mobility is higher.

Porosity and permeability are higher, but in carbonates, surfactant chemicals are needed because the oil sticks to the rock – so by definition you will have to inject thousands of tonnes of these chemicals which will stick on the rock surface, which raises the problem of profitability and economical production.”

However, Montaron says in the next five years the industry will undertake a great many more pilots for EOR in carbonate fields.

“Already we are seeing some interesting results from CO2 injection in carbonates. People are increasingly experimental with surfactants, CO2, and some very clever techniques to find the best, which may be a combination of several methods.”

Pilots in carbonate reservoirs can be expensive. Each can last a course of several years. “In that time you have to inject thousdands of tonnes of chemicals, at a cost of hundreds of millions of dollars, which is affecting your bottom line. The outcome is uncertain, so there’s a financial risk element.”

“What we are aiming to do is to bring down the cost of running pilots. Imagine if the cost could be capped and some tangible answers obtained in less than six months, then the whole venture looks a lot more appealing. Within a timeframe of just one year, three different processes could be investigated and a realistic picture of where you want to invest in the future can be established.”

These mini-pilot schemes aim to have enough scope to capture the heterogeneity of the reservoir, and enable enough data capture to analyse everything that is happening in the downhole environment, so that recovery factors can be accurately gauged.

“The possibilities for pilot studies are exciting,” says Montaron. If ultimately CO2 works best this could really change the landscape of carbon capture in the Gulf countries.”

Looking ahead

A casual analysis of worldwide oil reserves and yearly production reveals some quite staggering figures. Currently we are producing roughly 87 million bpd – 32 billion barrels per year. This means, every year the industry has to find twice the remaining volume of oil in the North Sea just to meet reserve-replace targets.

“Out of this 32 billion barrels produced each year almost 22 billion barrels are coming out of sandstone reservoirs. We are emptying the sandstone reserves much faster than the carbonate fields. The reserves and production ration in sandstone fields have around 20 years production time left. The proven and probable reserves in carbonate fields have around 80 years production left, so around four times more.”

This means that as time goes by the market share of carbonate reserves is increasing.

“Because we are emptying the sandstone reservoirs so fast it is possible that in 30 years we could be in a situation where 75% of the global reserves are in carbonates.”

“Traditionally we had been replacing reserves with more discoveries in sandstone than in carbonates. But something happened in 2007 that changed all of that,” says Montaron.

“An oil and gas company discovered a field 300 kilometres offshore of Rio de Janeiro in the Santos Basin, which was a truly huge carbonate field below a thick salt layer.”

The hydrocarbons in the Tupi and Carioca Field are an ultra-deep water environment buried beneath 2000 metres of water, 1000 metres of rock, and 2000 metres of salt.

“We don’t know exactly how much is there, but it’s a huge amount of oil. This field is particularly interesting because it is below a huge deposit of salt, which is a perfect seal.

That means the entire hydrocarbon reserve that was there before is still held in place. There are no leaks.”

There are plenty of areas worldwide where there are large salt deposits that fit a similar profile. “Offshore Angola and the Mediterranean spring to mind. Six million years ago the Mediterranean region was almost isolated from the Atlantic, and it evaporated leaving a massive layer of salt.

It’s not impossible that we could discover a vast amount of oil underneath these subsea salt deposits. This sort of well was not economical five years ago, but with the price where it is now, they are very viable. These sub-salt carbonate territories may well be the next exploration boom.”