An Interactive 5-Day Training Course
Carbonate Reservoir Characterization
Rock Typing and Permeability Prediction
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Duration
5 Days
Price
$ 3,500
Starting From
08 Mar 2027
Home Geology and Geoscience Carbonate Reservoir Characterization
Carbonate Reservoir Characterization
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Carbonate Reservoir Characterization - GG-CRCH-PEA27
| Code | Date | Time | Duration | Location | Currency | Early Bird Fee Per Person |
|---|---|---|---|---|---|---|
| GG-CRCH-PEA27 | 08 - 12 Mar 2027 | 10 AM CST | 4 Hours Per Day |
Online |
USD |
3500 |
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Carbonate Reservoir Characterization
Description
Characterising a carbonate reservoir for development is a different problem from describing its geology. The development requires a model that predicts flow, which means it requires permeability distributed in three dimensions, saturation that is consistent with the pore system, and a representation of fractures and of dual porosity behaviour where these are present. Carbonates resist each of these: permeability is not a function of porosity, saturation evaluation is complicated by microporosity, and fracture systems are sampled by very few wells.
This training addresses the characterisation workflow directly. Rock typing is developed first and treated as the organising framework, with pore type classification, petrophysical rock typing methods, the relationship between rock type and capillary behaviour, and the reconciliation of geological and petrophysical rock types. Carbonate petrophysics follows, covering log response in carbonates, porosity determination, the microporosity and high water saturation problem, resistivity interpretation, nuclear magnetic resonance applications and borehole image log interpretation. Permeability prediction is then developed through rock type based transforms, flow zone indicator methods and well test calibration. Fractures are treated in detail: characterisation from core and image logs, fracture modelling approaches, and dual porosity reservoir behaviour. Static modelling follows, covering framework construction, rock type distribution, property population and upscaling for carbonates. The training closes with the integration of well test, pressure and production data into the characterisation, and the surveillance of carbonate reservoirs.
Rock typing is the only workable framework for carbonate permeability prediction. Since porosity alone does not predict permeability, the reservoir has to be divided into units within which a porosity permeability relationship does hold, and those units are defined by pore type and pore throat size distribution rather than by depositional facies. A properly constructed rock typing scheme produces several transforms applied to their own rock volumes, each with far less scatter than a single field-wide relationship, and the resulting permeability model is the main determinant of simulation behaviour.
Microporosity makes carbonate saturation evaluation systematically misleading. Micropores within grains or micritic matrix hold water at irreducible saturation, so a log-derived water saturation of forty per cent in a carbonate may correspond to a producing interval with no free water, while the same value in a sandstone would indicate a transition zone. Fields have been written off and intervals left unperforated because of this. Resolving it requires capillary pressure data, nuclear magnetic resonance measurement or production evidence, and it requires the saturation height function to be built by rock type.
Fracture characterisation is constrained by sampling. Fractures are observed in core over a few tens of centimetres of borehole diameter and on image logs over the borehole wall, and from these the orientation, intensity and aperture distribution of a field-wide network must be inferred. Well tests see fracture permeability over a large volume but do not locate the fractures. The practical approach combines core and image log observation, structural reasoning about which fractures should be open under the current stress field, well test permeability as a bulk constraint, and production behaviour as evidence of connectivity.
Finally, dynamic data constrains carbonate characterisation more than it does clastic characterisation, because the static uncertainty is larger. Well test permeability thickness compared against log-derived values indicates whether fractures contribute. Pressure communication between wells indicates connectivity across mapped barriers. Early water breakthrough indicates fracture or high permeability pathways. Each of these should feed back into the static characterisation rather than being absorbed into history matching parameters.
By the end of this training, participants will be able to:
- Construct pore type based rock typing schemes for carbonate reservoirs
- Reconcile geological facies with petrophysical rock types
- Evaluate carbonate reservoirs petrophysically including the microporosity problem
- Build saturation height functions by rock type
- Predict permeability using rock type based and flow zone indicator methods
- Interpret nuclear magnetic resonance and image log data in carbonates
- Characterise fracture systems from core, image log and well test data
- Assess dual porosity and dual permeability reservoir behaviour
- Construct static models appropriate to carbonate reservoirs
- Integrate well test, pressure and production data into the characterisation
Organisations sending participants to this training will:
- Improve permeability prediction and simulation reliability in carbonate reservoirs
- Reduce saturation evaluation errors caused by microporosity
- Avoid bypassing producible intervals misread as water bearing
- Improve fracture representation and dual porosity modelling
- Reduce history matching effort through better static characterisation
- Build advanced carbonate characterisation capability for producing assets
Participants will:
- Build and defend a carbonate rock typing scheme
- Evaluate carbonate logs including microporosity-affected intervals
- Predict permeability by rock type rather than by single transform
- Characterise fractures and assess their flow contribution
- Construct carbonate static models fit for simulation
- Build advanced capability for carbonate development work
- Reservoir geologists working on producing carbonate fields
- Petrophysicists evaluating carbonate reservoirs
- Reservoir modellers building carbonate static models
- Reservoir engineers working on carbonate simulation and surveillance
- Integrated subsurface team members on carbonate assets
- Technical staff reviewing carbonate reservoir models
- Experienced geoscientists requiring advanced carbonate capability
Module 1 - Carbonate Reservoir Heterogeneity
- Scales of carbonate heterogeneity
- Depositional against diagenetic heterogeneity
- Pore type distribution and its controls
- Stratigraphic layering and flow units
- Permeability contrast and its consequences
- Vertical and lateral heterogeneity patterns
- Why carbonate reservoirs underperform forecasts
- Characterisation objectives for development
- Data requirements and acquisition planning
- Building a characterisation workflow
Module 2 - Pore Systems and Rock Typing
- Pore type classification for petrophysical purposes
- Pore throat size distribution and its measurement
- Mercury injection capillary pressure data and its interpretation
- Rock typing concept and its objectives
- Petrophysical rock typing methods
- Flow zone indicator and reservoir quality index
- Winland and Pittman pore throat approaches
- Lucia rock fabric classification
- Geological against petrophysical rock types
- Reconciling the two and the value of doing so
- Number of rock types and practical limits
- Validating a rock typing scheme
Module 3 - Carbonate Petrophysics
- Log response in carbonate lithologies
- Porosity determination from density, neutron and sonic
- Lithology determination and mineral solution
- Secondary porosity identification from log combinations
- Resistivity interpretation and the m exponent problem
- Archie parameters in carbonates and their variation
- Microporosity and apparent high water saturation
- Shaly carbonate and clay effects
- Nuclear magnetic resonance logging and T2 distributions
- Permeability estimation from nuclear magnetic resonance
- Core to log calibration in carbonates
- Common carbonate log evaluation errors
Module 4 - Saturation and Capillary Behaviour
- Capillary pressure in carbonate pore systems
- Capillary pressure measurement methods
- Saturation height function construction
- Saturation height functions by rock type
- Free water level and transition zone definition
- Thick transition zones and their causes
- Irreducible water in microporosity
- Wettability in carbonates and its variability
- Mixed and oil wet carbonate behaviour
- Relative permeability by rock type
- Residual saturation and its measurement
- Reconciling saturation models with production evidence
Module 5 - Permeability Prediction
- Why single porosity permeability transforms fail
- Rock type based permeability transforms
- Flow zone indicator methods
- Permeability from pore throat data
- Permeability from nuclear magnetic resonance
- Image log based permeability indicators
- Vuggy and fracture permeability contributions
- Permeability anisotropy in carbonates
- Scale dependence: core, log, well test
- Well test permeability as a calibration constraint
- Reconciling permeability across scales
- Permeability uncertainty and its propagation
Module 6 - Fracture Characterisation
- Fracture types and their origins
- Tectonic, diagenetic and stress release fractures
- Fracture description in core
- Borehole image log interpretation for fractures
- Open against mineralised fracture discrimination
- Fracture orientation, intensity and aperture
- In situ stress and fracture openness
- Fracture corridors and their identification
- Karst and cave systems as flow paths
- Well test signatures of fractured reservoirs
- Mud loss and drilling evidence for fractures
- Discrete fracture network modelling in outline
Module 7 - Static Modelling of Carbonate Reservoirs
- Stratigraphic framework construction
- Layering choices and flow unit definition
- Rock type distribution and its modelling
- Property population by rock type
- Modelling diagenetic overprints
- Dolomite body modelling
- Karst and collapse feature representation
- Fracture network incorporation
- Dual porosity and dual permeability model construction
- Upscaling carbonate reservoirs and its difficulties
- Model validation before simulation
- Uncertainty representation in carbonate models
Module 8 - Dynamic Integration and Surveillance
- Well test interpretation in carbonate reservoirs
- Permeability thickness against log-derived values
- Boundary and compartment identification
- Interference testing for connectivity
- Material balance in carbonate reservoirs
- Early water breakthrough and its causes
- Matrix to fracture transfer and imbibition
- Gravity drainage in fractured carbonates
- Production logging and its interpretation
- Tracer testing in fractured reservoirs
- Feeding dynamic evidence back into static characterisation
- Surveillance programme design for carbonate fields
Upon successful completion of this training course, delegates will be awarded an official Certificate of Completion issued by the Petroleum Engineers Association (PEA), an ISO 9001:2015 certified training organization. The certificate carries 10 Credits and formally records the total learning hours completed.
Each certificate is signed by the Course Facilitator and the CEO of the Petroleum Engineers Association, and serves as verifiable proof of professional training that delegates can present to employers and professional bodies worldwide.
Frequently Asked Questions
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PEA reserves the right to make reasonable adjustments to course content, trainers, or schedules where necessary, without entitling delegates to a refund. Comprehensive details of each course — including objectives, target audience, and content — are clearly outlined before enrolment, and it is the responsibility of the delegate to ensure the course's suitability prior to booking.
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