Competency Matrix for Reservoir Engineering




Minimum Competence

Approximate Years of E&P Experience = <1

Minimum Competence

Approximate Years of E&P Experience = 5

Reservoir Characterization
1 Geology Be familiar with the fundamentals of general, structural, and petroleum geology. Be able to apply the fundamentals of general sedimentology, structural, and petroleum geology to reservoir characterization and geological modeling. Uncertainty analysis in reservoir modeling. Basin modeling.
  Understand geology from an engineering point of view and be familiar with production performance, including the potential drive mechanisms. Be familiar with the physical arrangement (faults, layers, folds, shale barriers, etc.…) and connectivity of the reservoir and be able to apply flow properties of different parts of the reservoir and understand the behavior of water cut, reservoir pressure, and gas-oil ratio. Be able to screen data and check for consistency.
2 Geophysics Be familiar with the geophysical methods used in stratigraphic characterization and basic seismic attributes common to hydrocarbon bearing rock volume. Be familiar with acquisition, inversion and interpretation of 2D, 3D and 4D acquired seismic as well as application to rock and fluid property quantification. Applicability to drilling and pore pressure estimation also expected. Understanding of various downhole and surface application tools to the transmission of induced waveforms through the Earth’s surface is required. Design and execute downhole or surface condition acquired seismic programs (ex. VSP versus vibes). Understand the array design and check-shot subsurface ties to access all seismic quality etc. Applied inversion, filtering, discontinuity and acoustic integration expected. Identification of sequence stratigraphic continuity, DHI’s, assistance in wellbore path assessment, and application of seismic to geosteering are all required. Fault identification and analysis critical to the discipline. Ability to understand reflectivity, geology and sedimentology is important to the skill set. Pore Pressure prediction and fracture gradient assessment are also expected skill sets of the discipline.
3 Petrophysics Be familiar with the principles of petrophysical information. Be able to apply and integrate petrophysical principles and core data into reservoir characterization.
4 Mineralogy Be familiar with the common mineralogical properties of reservoir rocks. Be able to recognize mineralogical properties of reservoir rocks and integrate these (as appropriate) into reservoir characterization.
5 Geomechanics Be familiar with the basic principles of reservoir geomechanics (i.e., identify stress-dependent rock properties). Be able to relate reservoir properties to a given stress field and changes during depletion and injection (i.e., assess stress-dependency) to understand impact of stress field change to reservoir condition (i.e., infill well drillability, interwell communication, etc.). Wellbore stability modeling.
6 Logging Be familiar with the fundamental principles of well logging. Be able to interpret common open-hole and cased hole well logs for reservoir description.
7 Core data and Rock Properties Be familiar with coring techniques, core retrieval, recovery, wellsite handling, and preservation. Be knowledgeable about mineralogy and tools to characterize petrophysical and flow properties. Be knowledgeable about pore and pore throat network and reaction with various fluids. Knowledgeable about physics of fluid flow in porous media, directional permeability and Darcy’s equation. Knowledgeable about core cleaning, Dean Stark analysis, Routine Core Analysis, RCA. Knowledgeable about multiphase flow and role of capillarity, viscous and gravitational forces in reservoirs. Be familiar with unconventional rocks and matrix, fracture system and role of geochemistry and rock mechanics using core imaging. Be able to design coring program for an exploration, appraisal and development well. Deign a safe wellsite handling and preservation for sandstone, carbonate and shale reservoir. Design a rock characterization program consisting of core description, imaging, ore gamma and CT scanning to quantify heterogeneities at different scale and rock typing for capturing reservoir properties at different scales. Become knowledgeable about SCAL program consisting of W/O, W/G/ Condensate-Gas, their hysteresis, QC and modeling. Develop knowledge about integration of RCA and SCAL with geological and petrophysical information and their applications for in-place calculation, reservoir simulation studies and VOI. Be familiar with Digital Rock Technology and integration with petrophysics, near wellbore testing, geochemistry and rock mechanics for characterization of Unconventional and tight formations. Be familiar with data basis, AI, data analytics and Machine learning. Arrange to visit a core analysis laboratory.
Pressure, Rate, and Formation Testing
8 Short-term Pressure Transient Analysis (PTA) Know pressure-transient test options to obtain specific reservoir characteristics. Be able to select appropriate test for specific characterization needs (flow vs shut-in tests; production vs. injection tests, single-well vs. interference tests, etc.) and appropriate procedures for running tests. Concept of convolution and deconvolution.
    Be able to assess the value of PTA (value of information, i.e., when to run a pressure-transient test)
  Be familiar with the foundations of PTA, including the concepts of radial, linear, and spherical flow in a well, and the general concept of power-law behavior. Be familiar with the travel of the pressure pulse (diffusivity concept) in the reservoir and the radius (distance/volume) of influence concept
    Recognize properties of infinite-acting and boundary dominated flow periods (how pressure changes with time)
    Recognize the differences between oil and gas well tests and be familiar with the pseudo-pressure and pressure-squared approaches for gas well tests
  Be familiar with the PTA of vertical, fractured, horizontal, and fractured horizontal well responses in homogeneous, naturally fractured, and layered reservoirs Be able to distinguish pressure and derivative characteristics of vertical, fractured, horizontal, and fractured horizontal wells in homogeneous, naturally fractured, and layered reservoirs
    Be able to identify wellbore-storage influenced, infinite-acting, and boundary dominated flow periods on well-test data. Also calculate distance to boundaries and effect of condensate banking on pressure derivatives.
    Be able to identify flow regimes associated with the well and formation type
    Be able to recognize the signatures of fractures, faults, impermeable barriers, layers, and composite reservoirs
  Be able to analyze basic pressure-transient tests, such as drawdown, buildup, and drill-stem tests Be able to identify flow and shut-in periods on raw data and match the pressure and rate recordings (transfer relevant data from well record to analysis file)
    Be able to recognize flow and shut-in periods of a drill-stem test and estimate initial pressure, skin and permeability
9 Rate Transient Analysis (RTA) Be familiar with long-term performance analysis (RTA) Be able to apply RTA to estimate volumetric reservoir properties
10 Formation Tester Analysis (FTA) Be familiar with FTA Be able to apply FTA to assess "very-near" well properties
11 Scales of Measurements and Information Be familiar with the scales of reservoir characterization information based on the sources and tools used Be able to recognize and reconcile scale differences required to integrate multiple data sources in reservoir characterization
Reservoir Engineering
12 Flow in Porous Media Be familiar with the principles of flow in porous media considering Darcy and non-Darcy behavior, incompressible, slightly compressible, and compressible fluids, the equations for laminar and non-laminar flow, and the concepts of normal and anomalous diffusion, transient and boundary-dominated flow behavior, using constant rate and constant pressure as wellbore conditions. Understand the concepts of skin factor, productivity index, and inflow performance relationship. Be familiar with the concepts of coning in vertical and horizontal wells, etc. Be able to use physical and mathematical descriptions of fluid flow in porous media, considering radial, linear, spherical and hemispherical flow in a well, for single-phase, two-phase, and three-phase flow. Understand the line-source and finite wellbore solutions, and the implications of transient, steady-state and pseudosteady-state flow. Be able to apply the principle of superposition, and different inflow performance relationships. Understand and estimate the critical production rate and breakthrough time. Understand flow resistance concept.
13 Reservoir Drive Mechanisms Be familiar with reservoir drive mechanisms and understand their influences on performance Be able to recognize a given reservoir drive mechanism from geologic, petrophysics, SCAL and reservoir performance data and incorporate into a reservoir model
14 Material Balance Be able to understand the basic assumptions in the material balance equation and derive and explain simple material balance equations and assumptions. Understand and estimate average pressure from build-up tests. Be able to apply material balance equations for black oil, dry gas, and abnormally pressured reservoirs, to estimate initial hydrocarbon volumes in place, predict future reservoir performance, and predict ultimate hydrocarbon recovery.
15 Rock Properties Be familiar with the estimation of porosity and permeability from laboratory data Be able to estimate rock-type and facies-based porosity and permeability using laboratory data
16 Petrophysical Correlations Be familiar with the relations of petrophysical properties (e.g., porosity, saturation, permeability, etc.). Be able to correlate petrophysical properties (e.g., porosity, saturation, permeability, etc.).
17 Capillary Pressure and Relative Permeability Be familiar with capillary pressure phenomenon, the concept of relative permeability for the wetting and nonwetting phases, the drainage and imbibition processes and hysteresis effects. Be able to estimate and apply capillary pressure and relative permeability data for fluid distribution, reservoir characterization, remaining and residual fluid saturation at reservoir conditions. Be able to determine fluid contacts and FWL.
18 Multiphase Flow in Reservoirs Be familiar with the fundamental concepts of multiphase flow in porous media, including the factors to consider in waterflooding. Be able to recognize and apply the dynamic behavior of multiphase flow systems to reservoir problems, including formation damage and bypassed hydrocarbon
19 Phase Behavior (PVT) of Hydrocarbon Fluids Be familiar with the fundamentals of phase behavior (PVT) as these relate to hydrocarbon fluid distribution in reservoirs. Be familiar with the use cases and where and how to get the relevant information and being able to ask the right questions. Be able to quality check basic PVT data for inconsistencies. Understand the various tests and deduced parameters for the use cases. Be able to apply oil and gas PVT properties and correlations for use in reservoir modeling and production forecasting. In addition, understand the role of PVT data for reservoir surveillance. Being able to understand what is involved in surveillance or surface samples is also a plus to be able to associate the information to the reservoir evaluation.
20 Molecular/Nano-Scale Phenomena Be familiar with molecular/pore-scale interactions of fluids and rocks and their impact on flow in porous media Be familiar with molecular/pore-scale modeling for storage and transport of fluids
  Be familiar with intermolecular forces, structure of fluids, and their impact on properties of bulk and interface. Be familiar with molecular scale transport mechanisms especially diffusion. Be able to employ adsorption models to predict separation of components to surfaces.
    Be able to estimate diffusion coefficients and determine rates of diffusive transport or toward equilibrium.
21 Numerical Reservoir Simulation Describe objectives of a typical simulation study. Differences between green and brown field applications. Explain workflow required for the calibration (history matching) of the model, and how it impacts the objectives.
  Describe the sources of static reservoir properties that are input to the models. Describe their impact on study objectives. Explain how uncertainties in the static model are handled in simulation. Explain deterministic characterization and stochastic realizations. Explain assumptions behind upscaling.
  Describe the circumstances where one may use black oil, compositional, thermal, and chemical simulation models. Explain differences in data requirements for black oil, compositional, thermal, and chemical simulation models.
  Describe the concept of wettability, its impact on capillary pressure and relative permeability curves. Explain how modifications in relative permeability curves can impact simulation model outcomes.
  Describe the conditions where single-well, cross-sectional, pattern, sector and full-field models can be used. Explain the assumptions behind single-well, cross-sectional, pattern, and sector models, and how they may impact objectives.
  Describe primary design features of a simulation model such as grid size, orientation, fluid type and how to align those with study objectives Has developed single well models for coning studies, mechanistic modeling, or EOR processes, among other possibilities. Be able to build fit-to-purpose model.
  Describe the reason behind finite differencing in space and time. Describe radial, Cartesian, corner-point geometry, Voronoid grid models and importance of time steps. Explain how grids should be oriented, the impact of grid size on displacement processes, and approximations associated with local grid refinement and grid coarsening
  Describe how simulation models are initialized. Explain gravity-capillary equilibrium, free water level, impact of wettability, difference between drainage and imbibition Pc curves.
  Describe types of dynamic data used in reservoir simulation. Explain anticipated accuracy for the injection and production data, static and dynamic pressure data. Explain how they are used in model calibration process.
  Describe the objectives of model calibration. Explain the process of model calibration. Explain how computer assisted history matching can be performed.
  Describe the accuracy anticipated in predictive simulation runs. Explain the types of dynamic constraints that can be used in predictive runs. Explain sources of uncertainty in predictive runs. Explain design of experiments.
  Describe the main characteristics of fractured reservoirs and main components and representations of DPDP simulation models. Describe Warren-Root formulation. Explain how gravity, capillary and viscous forces impact fluid flow between fractures and matrix. Explain the differences among dual-porosity, dual-permeability and n-porosity models, and when each can/should be used.
  Describe the modeling of hydraulic fracturing process. Explain how different types of deformation and poroelasticity are captured/represented in models. Explain how proppants are represented in simulation models.
  Describe how a simple simulation model can be prepared (pre-processing), and how the outcomes can be analyzed (post-processing). Explain how data quality can be checked for ALL the information that goes into a simulation model. Explain various types of post-processing tools (plots/graphs/maps) that can be used to analyze the results and their pitfalls.
22 Waterflooding and Gas injection Be familiar with (a) principles of waterflooding and fractional flow theory; (b) gas injection principles such a gravity drainage process; (c) concepts of mobility ratio, displacement and areal sweep efficiency (d) Decline cure analysis (exponential, hyperbolic, etc.) for forecasting Be able to (a) screen reservoirs for waterflooding and gasflooding; (b) design and implement pattern surveillance programs; (c) understand flood performance drivers such as reservoir dip, heterogeneity, fluid properties and drive mechanisms for reservoir management (c) use analytical (DCA, dimensionless analysis) and numerical methods (streamlines etc.) for forecasting (d) Identify, forecast and propose infill and pattern realignment development opportunities
23 Improved/Enhance Oil Recovery (IOR/EOR) Be familiar with the principles of Improved/Enhance Oil Recovery (IOR/EOR). Understand the differences of thermal, chemical and miscible methods and their key tertiary recovery mechanisms. Have an awareness of Carbon Capture Utilization and Storage (CCUS) mechanisms Be able to (a) identify the right EOR method for a given reservoir candidate (b) perform laboratory/numerical screenings study for EOR evaluation; (c) design injectivity tests, EOR pilot and data acquisition program (d) interpret and analyze performance data from IOR/EOR pilots/projects for optimizing injectivity and recovery
24 Transient Flow Interpretation Be familiar with transient flow characteristics, their relations to reservoir properties, and flow and shut-in tests. Be able to diagnose flow behavior and estimate reservoir properties from PTA/RTA/FT and predict well performance and formation damage from flow and shut-in tests
25 Unconventional Reservoirs Be familiar with the definitions of unconventional reservoirs and the challenges related to achieving commercial production Be able to analyze and interpret short- and long-term production performance from unconventional reservoirs; be able to relate well development strategy (i.e., well spacing, completion design) to well performance
  Be familiar with shale gas production and hydraulic fracturing.  
Reservoir Management
26 Field & Asset Management Be familiar with the basic elements of field-scale projects and asset management Be able to combine engineering and economic principles for reservoir management; be able to apply various surveillance tools to monitor then optimize field production; be able to select appropriate EOR approach based on field characterization.
27 Petroleum Economics Be familiar with the fundamentals of project economics as applied to petroleum reservoirs Be able to use the principles of petroleum economics to assess economic viability of reservoir development projects; understand fundamentals differences between conventional and unconventional economics
28 Reserves Be familiar with SPE-PRMS reserve definitions Be able to apply accepted practices for the estimation of reserves; be able to apply reserve progression practices using appropriate tools
29 Production Forecast Be familiar with the production forecast methods and tools for conventional and unconventional reservoir systems Be able to forecast the future production profiles for conventional and unconventional reservoir systems (e.g., reservoir simulation, DCA, RTA).
    Be able to apply uncertainty analysis to production forecasting.
    Be able to construct and apply typical well production profiles (aka “type wells” or “type curves”) to forecast production for undrilled wells and wells with limited production histories
    Recognize the importance of and be able to take into account present and future well interference and multiphase flow on forecast production profiles


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