CHAPTER THIRTY-SIX: RESERVOIR DESCRIPTION

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CHAPTER THIRTY-SIX: RESERVOIR DESCRIPTION

36.00 Introduction to this Chapter
Reservoir description, sometimes called reservoir characterization or reservoir modeling, attempts to create a static and a dynamic three-dimensional description of an oil or gas reservoir, based on the one- and two-dimensional data from well bores and seismic surveys. A good reservoir description costs money and requires an integrated, multi-discipline approach.

The direct aims of the static reservoir description are:
  1. Extrapolate core data to uncored wells
  2. Define quantity and distribution of porosity, saturation, and permeability in each well
  3. Interpolate rock property data between wells
  4. Identify flow units from porosity vs permeability populations
  5. Build a knowledge base that evolves with the reservoir development

The direct aims of the dynamic reservoir description are:
  1. Test the static model for accuracy by matching production history
  2. Predict future performance under various operational scenarios
  3. Optimize production for maximum long-term economic return

A large fraction of the data for the static model comes from the petrophysical analysis, along with the core and petrographic data used to calibrate the log analysis. This Chapter attempts to tie together the petrophysical concepts from previous Chapters, all of which were designed to give you enough background and methods to discuss petrophysical results intelligently with other disciplines on the reservoir description team.

36.01 What Is Integrated Reservoir Description?
Reservoir Description means many things to many people. Thousands of consultants, contractors, and oil company department heads use the term with subtle or serious differences in meaning.

The petrographer thinks reservoir description means defining the pore geometry, pore size and pore throat radius distributions, and reservoir mineralogy, using thin section analysis, X-ray diffraction (XRD), and scanning electron microscopes (SEM). The modern term used is “porosity imaging”. The source material is drill cuttings or samples from cores. Their work is usually at the sub-millimeter level.

Core analysts think reservoir description is the measurement of porosity, permeability, grain density, capillary pressure, relative permeability, and electrical properties of the rocks, as well as facies description from observation of the depositional environment seen in slabbed core and core photographs. This work is at the centimeter level.

Petrophysicists see reservoir description as the evaluation of well logs to obtain reservoir rock and fluid properties, such as shale volume, porosity, water saturation, permeability, and lithology on a foot by foot basis, as well as sums and averages over specific reservoir units. This work is usually calibrated by core analysis and petrographic data where it is available. When well log data is combined with other geoscience data to form a coherent picture, it is called Integrated Petrophysics. Some work, such as analysis of formation microscanner images, may be at the centimeter level, but most is done at the tool resolution level – usually 0.3 to1 meter.

Geophysicists see reservoir description as the creation and mapping of seismic attributes or inverted seismic data to illuminate variations in reservoir properties between well control. This work is at the multi-meter level vertically and horizontally, but provides finer spatial resolution than logs and cores, which are dictated by well spacing. Attributes are usually calibrated to petrophysical log analysis results.

Geologists perceive reservoir description as the interpretation and mapping of petrographic results, core analysis, petrophysical rock properties, and seismic attributes into stratigraphic sequences and/or flow units. In the simplest cases, the mapping is based solely on correlation of raw log curves. In more elaborate studies, all of the measured and computed data will be mapped. Dipmeter and pressure transient analysis results may be introduced to assist in correlation or definition of reservoir boundaries or fault planes. These maps are also at the multi-meter level vertically and either the seismic shot point spacing or well spacing areally. The geological model obtained is the static reservoir description which, of course, can be monitored and varied over time by acquisition of new petrology, core data, or petrophysical rock properties from new wells or logs run through casing. Time-lapse (4-D) seismic may also be used to monitor hydrocarbon contact changes.

Reservoir engineers view reservoir description as the interpretation of pressure transient analysis results from drill stem tests or production tests. Flow capacity (permeability times thickness) and distance to reservoir boundaries (if they are close enough to be sensed by the pressure response) are the usual results obtained. In addition, pressure changes with production versus time provide grist for the material balance calculation mill. Production history (oil, gas, and water volumes versus time) coupled with decline curve analysis leads to predictions of ultimate hydrocarbon recovery. This work is also at the multi-meter level vertically and limited to the tested or produced wells only. Reservoir engineers are concerned with this dynamic reservoir description, as well as the static description for calculating reservoir volume and recoverable reserves.

Simulation engineers visualize reservoir description as a totally dynamic description of reservoir performance. They do use the static reservoir description (the geological model) as the basic foundation for the reservoir simulation. The bricks and mortar added to this foundation are the pressure and production data, and fluid properties, from the reservoir engineer. The object of the simulation is first to match production history, then to predict future behaviour of the reservoir. A good history match usually means that the geological model is reasonably accurate. The critical test is to compare the performance prediction with actual performance after a few years has elapsed. The reservoir simulation grid is usually a few to many meters vertically and many meters areally. Since more than one geological model could provide an adequate history match, calibration can only come with the passage of time and the arrival of new well data. Various production scenarios may be run in order to optimize reservoir recovery and economics.

The facilities engineer sees the dynamic reservoir model as a template for design and economic evaluation of production, gathering, treating, and pipeline  equipment required to handle the predicted reservoir performance. The timing of compressor installations, water disposal wells, and conversion of wells to injection are paramount considerations. Both undersized and oversized efacilities reduce the economic return from hydrocarbon production.

Drilling and production engineers use the various scenarios to plan in-fill drilling and re-completion operations on the wells in the reservoir.

Economic engineers use the dynamic and static models to predict cash flow, financing requirements, and investment decisions. Management and shareholders use the models to assist in making decisions as well.

“Integrated” reservoir models are based on the multi-discipline approach to the model. Integrated reservoir description combines geology, geophysics, petrophysics, reservoir engineering, production engineering, and numerical simulation. All of the disciplines listed above talk to each other and iterate their interpretations until all the data fits a common definition of the reservoir.

For example, a history match may fail because there is not enough reservoir volume to account for production and pressure trends to date. Reservoir volume can be increased by changing the parameters and cutoffs that go into petrophysical calculations, or the geological mapping can be more generous in contouring the data. One of the biggest problems is up-scaling from the sub-millimeter pore distribution through all the steps to the multi-meter grid cells of a reservoir simulation model. An open mind and a willing heart might be needed to overcome a lot of problems!

36.02 Flow Units
A flow unit is a rock body with a distinct pore system or porosity-permeability distribution. Each flow unit responds differently to fluid flow and production. Defining flow units in sandstone reservoirs is relatively straight forward using shale volume, porosity, water saturation, and permeability calculated from a petrophysical log analysis. Calibration to core data will help make the results believable.

Carbonate reservoirs are often more heterogeneous laterally than sandstone reservoirs. Porosity-permeability modeling within carbonates is possible provided it is carried out at an appropriate scale. Results should not be extended beyond individual flow units. Petrographic data, coupled with core analysis data, are used to generate log signature transforms that help to partition matrix (ineffective) porosity from effective (useful) porosity.

36.03 Petrophysics in an Integrated Reservoir Description
Clearly defined petrophysical goals and procedures help assure an efficient, technically sound result. The primary purpose is to give the petrophysical team a set of step by step instructions to assist them in project definition, planning, execution, and quality control. This will help to reduce errors and duplication of effort, and maximize project quality. A good plan and procedure keeps expectations in line with the data type and quality, as well as with budget and time constraints.

The petrophysical plan also helps to acquaint management, the client, and other groups who rely on the petrophysical results, with our methods and data requirements. Since integration of petrophysical data with larger projects is one of the important goals, guidelines on how to handle these relationships are described here.

This section is a step by step procedural guide. However, a number of motherhood statements are also included (eg. thoroughness, diligence, persistence, quality, resources). Although we all know that these factors are important, most unhappy clients, blown budgets, and delayed deadlines are caused by forgetting the basics.

The role of project managers and senior managers is also covered, since their support is crucial to the success of a project. Inadequate or late disposition of resources can only be corrected by senior management, no matter how willing the analytical staff may be.

The objective of the Petrophysical Phase is to provide an independent analysis of all producing or prospective reservoir zones seen in well logs. The project usually requires integration of the well log analysis with geological, stratigraphic, petrographic, conventional core, special core, completion, production, and reservoir engineering data.

The petrophysical phase of a project is usually a small to medium sized portion of a larger project. The usual project phases are:

      1. Geophysical Phase
      2. Geological Phase
      3. Petrophysical Phase
      4. Reservoir Engineering Phase
      5. Reservoir Simulation Phase

Although the phases appear to be sequential, there is considerable overlap and feedback between phases. Careful planning of all phases, and special attention to the inter-relationships between phases, will provide the optimum results and minimize costs.

For example, all Phases require log data, but of different types, intervals, scales, accuracy, and at different times in the life of the project. A decision has to be made as to who does the digitizing, who checks it, and is it done once for all to use, or done as needed by each group?

Similarly, Petrophysics requires core porosity vs permeability transforms and capillary pressure water saturation vs porosity relationships at an early stage; reservoir engineering needs this data much later. Should reservoir engineers provide this data to the log analysts, or vice versa?

The same questions must be answered with respect to petrographic data, fluid properties and contacts, geological structure, and other reservoir description data. All of this data is required by more than one of the Phases, but at different times.

Once decisions are made as to who does what, the project manager, and phase managers, must follow up to be sure the various tasks are being accomplished correctly and on time, and what other resources might be needed to help finish.

Integrated planning will coordinate the tasks of all phases of the project. Critical path timing can be displayed on PERT charts (Figure 2.XX). Better definition of resource needs and resource conflicts can be seen on Gantt charts (Figure 2.XX) and even more clearly on a Resource Gantt chart (Figure 2.XX). Although easy to make, these charts require constant updating, usually weekly. However, the effort is rewarded by catching resource deficiencies or conflicts before they proceed too far.

Additional entries on the Resource Gantt chart are helpful. For example, showing the timing of all inputs (source data) and outputs (deliverables) for a resource will show up conflicts that are not apparent in the resource allocation bars. The output of one Phase is often the input to another Phase. Assigning people to a Phase when their inputs are not available produces nothing but frustration.

While resources may need re-allocation to overcome some obstacles, this may incur some penalty due to broken continuity or loss of man-power. Adding people to a team has diminishing returns, which set in when a team exceeds 6 or 7 people. Conversely, adding or speeding up hardware and software usually has immediate, low-cost benefits, provided of course that these resources are truly tested and ready for release in a real-world environment.

Regular meetings of all Phase leaders are needed to keep the various activities coordinated. These should be short, have an agenda distributed in advance, and be adjourned promptly when the agenda is exhausted. Smaller meetings may follow to correct specific problems, but not all Phase leaders need to be present. If a Phase has a number of staff, Phase meetings may be needed to assemble progress data before the formal weekly meetings. Brief written weekly and monthly progress reports should be distributed to Phase leaders and the client.

The petrophysical team assists in data gathering, to ensure that all required data is available at an early stage in the project.

Open hole logs will be used to determine shale volume, effective porosity, water saturation, permeability, and (where possible) lithology. Cased hole log analysis will be performed, as needed, to assist in determining production characteristics, fluid movements, and dated fluid contacts. Swept zones, sweep efficiency, and residual oil saturation in partially depleted reservoirs can often be determined from modern open and cased hole logs.

Results will consist of summary tables of pore volume, hydrocarbon pore volume, flow capacity, average porosity, average water saturation, average permeability, and net pay after application of cutoffs and layer depth criteria.

These results will be used to generate reservoir property maps for estimation of original oil in place and flow capacity. The maps will be supported by detailed depth plots and listings of all input and computed data. Results will be used as input to the Reservoir Engineering and Reservoir Simulation Phases of the project, and also to assist in final assessment of mapping performed in the Geological Phase.

Reservoir zonation is often determined in the Geological Phase, in which formation tops, stratigraphy, facies, structure, and isopach maps will be prepared for use in the Petrophysical Phase. Mapping of petrophysical results and determination of volumetric original oil in place is usually done done as part of the Reservoir Engineering Phase, but may be delegated to the Geological or Petrophysical Group.

A technically and economically successful petrophysical analysis of a large number of wells in any project requires appropriate application of the following resources:

   1. a petrophysical manager/analyst
    2. one or more trained log analysts
    3. one or more trained log technicians
    4. dedicated computer hardware for each analyst and  technician, capable of fast processing    and plotting
    5. computer software capable of fast, error free computation
    6. trained digitizing staff with digitizing tables and software
    7. a client who can gain access to the required data and deliver it in a timely manner
    8. a work environment that keeps the team intact for the duration of the project, and in close
proximity to each other
    9. sufficient time to perform all data gathering, database building, data quality control, technical research, data processing, result verification, data presentation, and  reporting tasks
    10. a detailed plan that shows all the steps required for completion and quality control of the above tasks
    11. close integration with other Phases of the project to minimize duplication of effort and maximize quality of results for the client
    12. a corporate infrastructure that will quickly rectify any deficiencies in the application of needed resources
 

It is common to see Resources #1, 2, and 3 combined in one human brain/body. If timing constraints do not interfere, this approach gives good results.

Digitizing (Resource #6) is often done better by the log analysis technician (Resource #3) because he/she has a vested interest in the quality of the work. Another option is an out-of-house service bureau whose primary business is digitizing logs. Quality control of this function is critical, as all Phases of the project depend on a clean, complete, correct database.

Resources #11 and #12 are also important concerns and control time and budget over-runs as much as the individual actions of the Petrophysical Team.

Petrophysical data gathering is usually done as part of a team made up of personnel from several Phases, with a qualified log analyst as a member of the team. Sometimes, data gathering and inventory is done by a team from only one of the Phases. These people must be aware of all the data needed for the entire project, including petrophysics broad needs, not just those of their own Phase. To minimize effort later, data gathering must be done thoroughly and inventoried accurately.

If data is known or suspected to exist, it must be pursued diligently and persistently until all avenues are exhausted. If required data is truly not available, the client should be notified of the consequences immediately, along with a recommendation for additional work required to overcome the deficiency. For petrophysics, the missing data is often the electrical properties, petrographics, mineralology, water chemistry/salinity, and core porosity-permeability-grain density data we need to calibrate the log analysis.

The cooperation of the client in data gathering is critical. Data that is overlooked or deliberately held back reduces the quality of the results, to the detriment of the project and everyone involved in it, including the client representatives. A copy of the data inventories

should be given to the client, with a request to review and augment the database where possible.

A complete list of data required for petrophysics is listed below. Much of the data listed is needed by more than one Phase. However, each Phase should prepare its own data gathering list, so that all required data is properly itemized. The combined data gathering list should be provided to the client before the data gathering trip to acquaint them with our needs and expedite the gathering process.

To obtain optimum results, the petrophysical team requires all pertinent well data in a timely manner. If some requested data is not available or arrives late, it may not be possible to calibrate petrophysical results adequately. In such cases, a discussion of the data deficiencies will form part of the final report.

The Data Gathering Checklist is given below:

Project Definition To Be Provided By Client
 - Names and titles of client's key personnel
 - Brief overview of petrophysical requirements and problems
 - List of pools to be analyzed, brief geological  description, brief production history, fluid types,  water problems, special considerations for each pool
 - List of wells, zones, and intervals to be analyzed
 - List of cored intervals, footage recovered, formations encountered, interval analyzed, special core analysis intervals, type of special analysis
 - List of logs available and intervals covered
 - List of XY coordinates and KB elevations, with base map
 - List of log curves and intervals digitized by client
 - List of log curves and intervals to be digitized by consultant
 - List of wells that require TVD correction
 - List of workovers in each well, with perf intervals, date, test and IP results
 - List of formation tops in each well
 - Sample well logs and core data from a cored producing zone
 - If project definition cannot be supplied by the client we will do this work BEFORE a final proposal and budget is made

Geology Data To Be Provided By Client
 - Technical reports and papers on depositional environment, structural geology, and petrography
 - Geological cross-sections and stratigraphic correlation chart, formation descriptions
 - Structure map with well locations, faults, fluid contacts
 - Existing porosity, saturation, net pay, permeability, pore volume, hydrocarbon pore volume,and flow capacity maps
 - If cross-section and structure map do not exist, they will be provided by Geological Phase BEFORE Petrophysical Phase begins.
 

Petrophysical Data To Be Provided By Client
 - Sample description (lithology) logs and mud logs
 - Core description
 - Conventional and special core analysis listings
 - Capillary pressure plots and listings - Electrical properties plots and listings (Formation Factor, A, M, N)
 - Formation water chemistry analyses and resistivity data
 - Formation temperature vs depth data.
 - Well logs - all porosity, lithology, resistivity, and production logs, paper copies required
 - Deviation surveys or TVD listings
 - All above data on digital tape or disc, as well as paper. where possible
 - Petrographic, thin section, SEM, and XRD data
 - Previous reports outlining net pay, water saturation, porosity, net pay cutoffs, etc
 - Any permeability vs porosity transforms previously used
 - Any A, M, N transforms and RW data previously used 

Drilling/Completion/Testing Data
 - Well ticket data
 - Legal name and location
 - Casing run, depths, type and weight, amount and type of cement
 - Spud and rig release dates
 - Formation top names, and depths
 - Perforated intervals, type, spacing, and dates
 - Cored intervals, type, size, recoverym and dates
 - Oil analyses, gravity, and GOR
 - Gas analyses, composition, and density
 - Original and secondary oil/water, gas/oil contacts
 - Completion and workover history
 - DST tests, intervals, and results
 - RFT tests, intervals, and results
 - Perf tests, intervals and results
 - Deliverability tests, eg: AOF (gas) and IPR (oil)
 - Any special drilling problems: blow-outs, lost circulation zones, stuck in hole, fractures, over pressure
 - Treatment and stimulation history
 - Production history plots, including monthly oil, gas, water, and condensate production
 - Injected volumes of gas and/or water used for disposal or enhanced recovery
 - List of accepted formation temperatures
 

Preparation of the digital log database is usually the responsibility of the Petrophysical Team.  The requirements of other Phases of the project must be made known at an early stage so that appropriate curves and intervals are digitized for all potential uses. An inventory of hardcopy logs, digitized curves, and intervals will be maintained by Petrophysics.

If other Phases prepare log digits for their own use, they should coordinate their efforts with Petrophysics to minimize duplication.

The digital log database must reside on one computer under the control of the Petrophysical Team. This database is termed the Master Petrophysical Database and cannot be removed or modified except by authorization of the Petrophysical Manager. It will be backed up on a weekly basis for safety, with a copy held off premises.

The integrity of the Master Petrophysical Database is a critical function, and is the responsibility of ALL petrophysical staff. Problems or deficiencies in data or procedures should be reported immediately to the Petrophysical Manager.

Copies of the Master database may be distributed to other computers or work stations. However, this data becomes the responsibility of the users on those work stations. At least one copy of the data should be in read-only files on the workstation so that users cannot corrupt the files accidentally. Users may copy these files to their own directories for their own use. If accidents occur, the data can be revived from the read-only files.

If a distributed copy is in use, it is the responsibility of the user to request updates and to report problems to the Petrophysical Manager. However, users have a responsibility to make every effort FIRST to confirm and define the problem by comparing their data with the read-only files and the hardcopy logs.

Log data quality control will be undertaken by the Petrophysical Team as the database is being prepared. If problems are identified to be caused by inadequate in-house digitizing, further training will be implemented. Service bureau digitizing will be rejected if errors are not corrected quickly.

Quality control will consist of the following procedures:
    1. If data is provided in digital form, load and print catalog of all known data files and compare to data inventory. If data is digitized in-house, proceed as detailed below.
   2. Plot raw data from top to bottom at 1:xxx scale.
   3. Inventory curves on data plot and depth interval covered by each curve.
    4. Compare curves and intervals to inventory of open hole logs, and itemize missing curves or intervals.
    5. Compare plotted curves to original logs, and list curves and intervals that need to be redigitized.
    6. Initiate (re)digitizing requests.
    7. Replot and recheck new digits.
    8. Update data inventory sheets. 

Petrophysical analysis will proceed on a pool by pool basis. The method employed for most studies will involve the following steps, which may vary depending on available data and project objectives.

   1. Gather and inventory available data, review well files, sample descriptions, drilling history, drill stem and production tests, completion and production history, and current status of each well, based on information in the well history files provided by the client.

    2. Review conventional and special core analysis data and core description on the cored wells, and enter all data into database. View available cores and describe fracture patterns and lithology. Initiate and monitor further core analysis if required.

   3. Prepare core porosity vs core permeability, and vertical vs horizontal permeability crossplots (by zone by well and by zone all wells) and determine best fit equations for each zone. Revise transforms after water saturation data has been calculated and calibrated to capillary pressure data.

   4. Crossplot porosity vs formation factor and saturation vs resistivity index from special core data, by zone by well, and by zone all wells. Determine appropriate electrical properties (A, M, and N) values from available special core studies, from modern EPT/MSFL logs, and/or from Pickett plots if suitable water zones exist.

   5. Prepare log database and print inventory of available logs by reading digital data (provided by the client) over required intervals, digitizing any missing curves or logs according to accepted log digitizing specifications. CHECK INVENTORY AGAINST HARD COPY LOG HEADINGS.

The curve complement will vary with the age of the logs, but will include deep and shallow resistivity, sonic, neutron, density, SP, gamma ray, photoelectric, and thermal decay time where available. Additional curves will be added as needed and where available. Old style neutron logs will be converted to a porosity scale. All data will be decimated to 1 foot or 0.3 meter increment.

   6. Plot all raw data and core data vs depth. Compare to original logs to verify scales, data quality, depth matching, and missing data. THIS IS AN ABSOLUTELY ESSENTIAL QUALITY CONTROL STEP AND MUST NOT BE OMITTED.

   7. Prepare initial log analysis and representative crossplots on cored intervals on key wells with modern log suites to calibrate porosity and permeability parameters, using the density-neutron-PE shale corrected complex lithology three mineral model for both shaly sands and carbonates. Shale volume will be determined from SP, GR, and density neutron crossplot (some methods are not appropriate in some zones). Only those crossplots that are necessary for choosing parameters will be made, but not all will be presented to the client.

   8. Select appropriate water resistivity and mud filtrate value for each zone and select appropriate calculation method for original reservoir and invaded zone water saturation.

   9. Determine effect of conductive non-clay minerals and adjust saturation accordingly.

   10. Adjust parameters as required and calculate final log analysis on cored wells, to obtain a good match to core data.

   11. Calculate log analysis on remaining wells with density-neutron-PE data, but no core data.

   12. When no PE is available, a 2 mineral model will be used. For old style neutron cases, lithology will be assumed using log analysis on offset wells or sample description for control.

   13. Calculate log analysis using the shale corrected sonic log model for wells with core and/or density neutron data, to calibrate sonic parameters.

   14. Calculate log analysis on remaining wells which have only sonic log data.

   15. Perform similar steps for wells with density only or neutron only, calibrating to core or offset density neutron or sonic data.

   16. Demonstrate calibration of log analysis porosity to core porosity using depth plots, crossplots, and/or regression analysis.

   17. For wells with ancient logs, determine approximate porosity from porosity mapping of offset wells, to aid in determining net pay in these wells.

   18. Determine secondary porosity, fracture location and fracture intensity from all available methods.

   19. After a few of each log suite are analyzed, write preliminary report and review preliminary results with client, and compare to geological cross sections and zoning concepts.

   20. Revise any methods or parameters and analyze remaining wells.

   21. Prepare cross sections to include all wells and compare shale, porosity, lithology, saturation, permeability, and fluid contacts from well to well. Check for consistency, geological variations, data errors, and analysis errors using Quality Control Checklist (on following page).

   22. Compare results to geological zoning and run final layer summaries.

   23. Calculate dated water saturation from thermal decay time log where available, and compare to original water saturation from resistivity logs.

   24. Determine and justify (if possible) shale, porosity, permeability, and water saturation cutoffs by comparing log analysis results to core data, production, and test data.

   25. Determine original and dated gas/oil and oil/water contacts to define gross intervals, checking with production and test data, properly adjusted for capillary pressure data and age of well.

   26. Correlate capillary pressure curves and log analysis saturations over transition zones.

   27. Calculate and print average porosity, average saturation, pore volume, hydrocarbon pore volume, flow capacity, and productivity summaries for each layer in each zone for mapping of reservoir properties.

   28. Prepare depth plots of raw data and answers for wells with any useable log curves and results at scales of 1:200 and 1:500, for correlation and mapping purposes, showing formation analysis results, core analysis porosity and permeability (where available), flags for bad hole, light hydrocarbons, and pay intervals, and other requested curves.

   29. Annotate tops, tests, cores, perfs, and fluid contacts on depth plots. Add annotation tail with this data, parameters used, and pay zone summaries.

   30. Print detail listings of all requested results for all zones.

   31. Present copies of necessary crossplots for each zone, with discussion and explanation.

   32. Write final report, documenting calculation methods, parameter selection, results, and conclusions, and discuss results with client.

   33. Prepare copies of IBM compatible data tapes or discs in LIS or LAS format containing raw data and results.

   34. Provide copies of results to other Phases as required through the duration of the project.

ABOUT THE AUTHOR

E. R. (Ross) Crain, P.Eng. is a Consulting Petrophysicist and a Professional Engineer with over 35 years of experience in reservoir description, petrophysical analysis, and management. He has been a specialist in the integration of well log analysis and petrophysics with geophysical, geological, engineering, and simulation phases of oil and gas exploration and exploitation, with widespread Canadian and Overseas experience.

His textbook, "Crain's Petrophysical Handbook on CD-ROM" is widely used as a reference to practical log analysis. Mr. Crain is an Honourary Member and Past President of the Canadian Well Logging Society (CWLS), a Member of Society of Petrophysicists and Well Log Analysts (SPWLA), and a Registered Professional Engineer with Alberta Professional Engineers, Geologists and Geophysicists (APEGGA)