Oil Review Middle East Issue Two 2010

AAS MORE THAN 60 per cent of theworlds remaining conventional oil isestimated to lie in carbonate reservoirs,the need to better understand

carbonate production capabilities particularly thegiant fields found in the Middle East becomesincreasingly important. But heterogeneous porositydistributions, intricate flow paths caused byfracturing, flow barriers and baffles are among thekey challenges that make carbonate reservoirsnotoriously difficult to characterise, and thereforeproduce.

Unlike sandstone, which in general is formedover time from deposits left behind by tides, riversand winds and is relatively homogeneous,carbonates are the result of diagenesis rather thanmechanical action, and are formed in place ratherthan transported and deposited in a sedimentarybasin. Calcium carbonate is also more chemicallyactive than the silica in sandstone and itsmechanical properties make it prone to fractures,subsidence and compaction. Relative to sandstonereservoirs, carbonates show a poor correlationbetween porosity and permeability, and no two

Networks of natural fracturesplay a crucial role in many oiland gas reservoirs they help

to drain hydrocarbons andother fluids

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Carbonate reservoirs are difficult to characterise, and therefore produce. Nevertheless,the complexities of carbonate reservoirs need to be overcome not least becausethey house much of the worlds remaining conventional oil.By Iain Bush, Schlumberger

An integrated approach to

fracture characterisation

Fracture corridors vary in length and size; a largefracture corridor might be 10 m wide, 100 m highand a kilometre long. Fracture corridors are notrestricted to carbonate environments. This fracturecorridor located in a clastic rock outcrop in Algeria,measured at up to 10 metres (33 ft) wide with novertical displacement but with many small fractures

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carbonate reservoirs are alike. Some carbonaterocks are also susceptible to subsidence andcompaction during production.

Flow networksMost carbonate reservoirs are naturally fracturedfrom microscopic fissures to kilometre-sizedstructures called fracture swarms or corridors.Fractures exist over a very wide range of scales andmay form complex flow networks. Understanding

these flow networks is fundamental to achievingbetter prediction and production performance.These networks can be characterised using high-fidelity measurements from multiple scales anddisciplines, and incorporated into a unifiedgeological model. Such geological models mayincorporate all fracture scales and should accuratelypredict fluid flow.

Networks of natural fractures play a crucial rolein many oil and gas reservoirs they help to drain

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Seismic to simulation variations

The Coil Shooting technique is expected to be

particularly effective indefining fracture corridors

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hydrocarbons and other fluids. Conductive fracturecorridors are major conduits for fluid flow in thereservoir. To obtain realistic dynamic reservoirsimulations, their positions must be mappedaccurately in the reservoir model furnishingessential information for locating injector andproducer wells to maximise reservoir sweepefficiency.

As for what constitutes a fracture corridor, atypical fracture corridor can consist of a hugenumber of parallel fractures densely packedtogether to form a volume that is typically a fewmetres wide, a few tens of metres high, severalhundred metres long and with a permeability wellabove 10 Darcy. These corridors act as majorconduits for fluid flow in the reservoir and can beresponsible for early water breakthrough. Tomaximise field production and total recovery, thelocation of fracture corridors within the reservoirmust be known.

Fracture corridors are particularly important forreservoirs with a tight matrix. In carbonateformations, for instance, permeability ratios of 1000or more between the rock matrix and surroundingfractures are common. Natural fractures tend to beorganised in families and oriented in particulardirections. Fracture corridors are easily distinguishedfrom other types of joint sets, have little or novertical displacement and are well marked by theireffect on morphology.

Next we turn to the detection of fractures in thereservoir. It is impossible to create a completepicture of all the fractures in a reservoir, but adetailed understanding of the fracture networks canbe built from a range of measurements. Usingdownhole instruments, the fractures intersectingboreholes can be detected and characterised. TheFMI* Fullbore Formation MicroImager provides aborehole image generated from up to 192 micro-resistivity measurements. Though limited in their

sampling of the reservoir volume, suchmeasurements provide detailed information such asorientation, depth and aperture of the fractures. Innon-conductive invert-emulsion mud systems, aclearer image of the fractures can be obtained usingthe OBMI* Oil-Base MicroImager tool. Data from welltests and production logging tests are also essentialto characterise the fluid flow around the wells.Further measurements that examine the inter-wellspace are required to understand how the fracturesobserved in the wells extend across the reservoir.

Seismic anisotropyThe power of seismic in this context has, inarguably,grown. Historically, the properties of diffuse fractureshave been characterised from seismic data throughthe indirect interpretation of seismic anisotropyobservations. Since the mid-1980s there has been agradual evolution in seismic acquisition andprocessing technology enabling not only more

accurate measurements of anisotropic velocities,amplitudes and attenuation, but also being able todetect fracture corridors.

The challenge of imaging through complexgeology (such as the folding and faulting inoverthrust geology) or analyzing the azimuthalvariations in seismic response to accuratelydetermine reservoir subtleties requires high-fidelityseismic data. This is combined with a requirement forfine sampling to characterise and remove noise fromthe data.

The UniQ* point-receiver acquisition andprocessing system can record up to 150,000 livechannels at a 2-millisecond sample interval. Theextremely high channel count of the system meansthat the right number of point receivers can bedeployed to optimise the imaging objectives andallow a full-azimuth (FAZ), broad-bandwidthapproach to seismic acquisition.

Offshore, the recently introduced Coil Shooting*single vessel FAZ acquisition technique records afull range of azimuths using only one vessel. Thetechnique acquires marine seismic data whilefollowing a circular path. The high fold and fullrange of azimuths achieved by the method providesfurther improvements to noise reduction andmultiple-attenuation over those already provided byparallel wide-azimuth geometries. The CoilShooting technique is expected to be particularlyeffective in defining fracture corridors thanks to theFAZdata it supplies.

Geological informationThe interpretation of high-quality, high-resolutionFAZ seismic data will enhance informationavailable on many levels, including anisotropyanalysis and inversion, and observations of subtlediscontinuities and scattering associated with sub-seismic faults and fracture corridors. Integrating thedifferent measurements and building arepresentative earth model helps provide a betterunderstanding of fracture networks. Understandingthe physics of these diverse measurements isimportant to extracting reliable geologicalinformation, particularly for seismic data processingwhere the detection of fractures requires anoptimised processing sequence.

Seismic anisotropy can be characterised bydetecting different wave properties (e.g. velocitiesand/or amplitudes) measured along differentdirections. While an alignment of fractures maygive rise to seismic anisotropy, interpreting fracturedistribution is not trivial. In general suchassumptions may not be appropriate. For example,two orthogonal sets of vertical fractures may beanisotropic but assuming a single fracture setwould lead to an incorrect interpretation.

The Fracture Cluster Mapping (FCM*) workflow,integrates seismic data, 3D seismic, boreholemeasurements and Petrel* seismic-to-simulationsoftware for characterising fractured reservoirs.Historically, only the properties of diffuse fractureswere characterised from seismic data. However,with FCM, the location of individual fracturecorridors can be detected and embedded into amulti-scale 3D reservoir model containing faultsand diffuse fractures.

The workflow begins with objective-drivenprocessing of the best available seismic datafocused on maintaining the highest possible signalbandwidth. Discontinuity Extraction Software (DES)can successfully identify coherent structuraldiscontinuities in a 3D dataset, but unconstrained,is likely to skip the subtle indicators of medium andsmall fractures. The FCM workflow constrains theprocess based on knowledge including regional andlocal structural geology, reservoir geomechanics,well logs, well tests and production data, to focus

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Using Q-Technology* as part of a multi-disciplinary seismic-to-simulation workflows, engineers and geologists are ableto develop a greater understanding of the complex flow-networks in carbonate reservoirs and better predictproduction behaviour

It is impossible to create acomplete picture of all the

fractures in a reservoir, but anunderstanding of the fracturenetworks can be built from a

range of measurements

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on possible fracture clusters. Various scenarios canbe tested, adjusting variables such as theorientation and the size of clusters, or associatingfracture patterns with known faults and/or folds.

Results are strongly dependent on the seismicacquisition geometry and data quality. To this end,there are stringent quality requirements on the 3Dseismic data to provide a meaningful input fordetecting fracture clusters. Bespoke design of dataacquisition and processing using point-receiver datamay be needed.

As for modelling the reservoir, fracture modelsmust accurately predict fluid flow channels tooptimise production. The geometry of the fracturesand the ways in which they form, however, makesmodelling them a challenge. Without accurate fieldmodels, operators can experience early and steepproduction declines.

Discrete Fracture NetworkPetrel seismic-to-simulation software combines theinformation from multiple domains into a unifiedrepresentation of the reservoir. The result is aDiscrete Fracture Network (DFN) model that makesa clear distinction between the diffuse fracturesthat can be modelled using geostatisticaltechniques, and the discrete fracture corridorhighways that must be identified and placed in thereservoir model at their exact field locations.

Geomechanical modelling with the VISAGE*reservoir geomechanics system, provides a keycalibration of the fracture model by modelling thestresses and strains in the reservoir. From anunderstanding of the different rock types in thereservoir, the geomechanical modelling can beused to derive the locations and orientations ofopen fractures. In this way the properties of thefractures in the geological model can be refinedand calibrated.

ECLIPSE* FrontSim software uses streamlinetechnology, allowing engineers and geologists tomodel fluid flow in fine-scale models containingfracture corridors, to screen multiple models, and tovalidate upscaling to coarser-scale simulationmodels. The 3D simulation grid contains thefracture porosity, permeability, and sigma factorrequired for a dual porosity or dual permeabilitysolution. The upscaled models can be fed intoECLIPSE finite difference modelling software toprovide a rigorous full-reservoir simulation. Withdynamic simulation, the fluid flow through thefractured models can be calibrated with productiondata to confirm the major flow paths.

The FCM workflow was applied over a fieldwhere the enormous size of the study area (largethickness of carbonates of around 3,000-ft) of lowporosity and low permeability, and where just a fewdata points (12 wells) across the area warranted anew approach for fracture characterisation todetermine how realistically fractures could beextrapolated beyond the well controls and howthey could be interpolated between the wells. Afurther study suggested a good correlation betweenwell productivity and the proximity of fractureclusters as predicted by the FCM workflow.TheFCM approach consequently had value in decidinglocations for new wells, planning well trajectories

(to avoid or intersect a certain type of fracturenetwork), and production predictions and, moreimportantly, to make comprehensive DFN models.

In conclusion then, characterising fracturedreservoirs requires the ability to integrate high-fidelity measurements from multiple scales anddisciplines.

It is also necessary to detect and locate fracturecorridors, and to build unified geological modelsthat incorporate all fracture scales. Geomechanicalcalibration and flow simulation are essential toaccurately predicting fluid flow. This providesessential information for locating injector and

producer wells that maximise reservoir sweepefficiency and avoid water breakthrough surprises.

An integrated approach to fracturecharacterisation will ultimately enable betterprediction and production performance for operatorsand service companies alike throughout the MiddleEast region.

Iain Bush, is Business Development Manager,Naturally Fractured Reservoirs at Schlumberger, a leading oilfield services providerhttp://www.slb.com*Mark of Schlumberger

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