1. SPWLA WFT SIG Houston, Texas September 27, 2011
Compartments for Beginners: Wellbore Formation Testing in the Real World
SPWLA WFT SIG
Houston, Texas
September 27, 2011

2. Why are we talking about this?
What has been the outcome of the last few years of data collection?
Compartments, Compartments and … more Compartments
How do we define the Value Proposition?
Importance of Sample Quality and Volume
Value of Information vs cost and risk
How do we plan and run the job?
Practical tips for adding value with new technology

3. The deepwater Appraisal problem: Reduce Subsurface Uncertainty in a cost-effective manner
Industry moving towards:
Ultra deepwater, deeper objectives
Non-amplitude and subsalt prospects
Less forgiving smaller targets
Appraisal problem is getting more difficult
Increased subsurface uncertainty
High appraisal costs makes reducing uncertainty expensive
$10MM to $30MM/well in deeper waters (data collection only).
Need to reduce subsurface uncertainty in a cost-effective way
Combining reservoir engineering and geochemistry in a valuable way to decide what data to collect for what cost and what is the acceptable risk to get this data

4. GOOD UGLY 2009 DEEPSTAR 9702 Appraisal Lookback: 28 DWGOM Fields
Two fields significantly outperformed expectations
Six fields significantly underperformed expectations
Of the remaining 22 fields 75% marginally underperformed and 25% marginally outperformed
In general, fields showed more complexity than anticipated
BAD RESERVES OUTCOME
GOOD
UGLY
BAD PRODUCTION OUTCOME

5. Key Tools for Appraising New Fields

6. Looking for Value Why are we talking about this?
Optimize Cost and Maximize Value
Apply Appropriate FEL
For a new field discovery
Uncertainty Management Plan
Assess the impact of fluids properties on project execution
Impact of compartments on Appraisal program
Compartments
Fluids
Impact
IMPACT
Exploration:
What is the likely value of this discovery? (oil quality and continuity)
How high a priority should this prospect get in the Appraisal Queue?
Development:
What are the “game changers”?
Effect on project architecture and selection of development options?

7. Compartments, Compartments and More Compartments
Compartment Risk will be determined based on how well:
Pressure trends for major and minor sands correlate over the field,
Pressure trends correlate vertically within each zone in each well,
How measured and theoretical fluid gradients compare,
How fluid properties correlate over the field (both PVT and bulk properties), and
A review of geochemical marker results.
Oil Fingerprinting
Mud gas Isotope Analysis
Solution Gas Isotope Analysis
Sulfur Isotope Analysis
Real-time techniques that are useful in the timeframe needed to make decisions to complete or sidetrack are limited.

8. Courtesy Arild Fossa, PowerWell Services
Exploration and Appraisal Activities Data Collection and Integration Toolkit
1 cm
1 m
1 km
GEOLOGY
SEISMIC
Static
CORES
LOGS
NEW PARADIGM: THE DISTRIBUTION OF PRESSURE AND FLUIDS IN THE RESEVOIR REPRESENTS A TYPE OF DYNAMIC DATA!
Distance of
investigation
WFT PRESSURES
FLUID PROPERTIES & GEOCHEMISTRY
Dynamic
WELLTEST
TRACERS
10-2 m
10-1 m
1 m
10 m
102 m
103 m
104 m

9. In the Appraisal and Development Phase How much sample do we need and why?
We need multiple fluid samples from different wells because spatial variations in fluid composition can reflect:
Faulting, compartmentalization and reservoir architecture
Filling history as an indication of geologic complexity
Proximity to fluid contacts and gravitational grading
Biodegradation, tar mats, loss of light ends and mixing events
and allow production allocation or mechanical troubleshooting with fingerprints
Water Samples: (500 to 1,000 cc per zone)
Hydrate formation, Scale, Souring and Corrosion potential, Salinity
Tahiti Field: Four conventional cores, over 500 pressure points, 33 fluid samples, M-21 Well Test
OWC
3 miles
Geochemical allocation of fluids during the Tahiti Well Test by Russ Kaufman and Stan Teerman
Relationship of optical density during Tahiti sample pumpouts with column height by Soraya Betancourt (SLB)

10. In the Exploration and Appraisal Phase How much sample do we need and why?
We need multiple sample bottles at each sample point because:
300 cc sample => minimum evaluation
Samples compromised during transfer or leakage during storage
Custody transfer and inventory mistakes
Multiple measurements required for confidence
Studies that usually require substantial volumes of oil (gallons, barrels):
Restored state core floods for SCAL
Completion/stimulation fluid compatibility
Flow loop testing
Emulsions key for oils <20 deg API
Larger volumes needed (1 Bbl)
From SPE 49067: “Identifying and Meeting the Key Needs for Reservoir Fluid Properties A Multi-Disciplinary Approach” B.J. Moffatt and J.M. Williams
Deepwater Project Learning: Major Capital Projects relying on Wellbore Formation Tester sample volumes are typically short of STO and live fluid prior to completion of all desired experiments.

11. In the Exploration and Appraisal Phase How much sample do we need and why?
Optimum Samples Volume needed for: Target:
PVT for reservoir and fluid flow simulation: GOR, Bo, density, viscosity
Volume: 1,000 cc Res Fluid / zone affect OOIP, rate and recovery
Geochemistry fingerprinting: Reservoir continuity and variability
Volume: 50 cc STO / zone Source rock typing, analogs
Hydrates, wax & asphaltene potential: Operability, cost,
Volume: 100 to 200 cc Res Fluid / zone development options
Crude Value: Market Value, STO properties
Volume: 10 gallons STO / zone and character, refinery options
Emulsion / Foaming: Viscosity variation with water cut;
Volume: 10 gallons STO / zone separation time; foam stability
Chemical Screening: Effectiveness of
Volume: 10 gallons STO select chemicals

12. Tahiti Field: OBM contamination corrections
How clean does it need to be? Oil Based Mud Contamination
Oil-based mud and hydrocarbon additives to water based muds can contaminate fluid samples, affecting the results of PVT and STO testing.
Plan sampling program to minimize contaminants.
Quantify the OBM components and correct for their effect.
Make sure you capture relevant OBM samples. Consider contamination of your sample from other zones (or other wells).
Until recently most OBM were 2-3 component mixtures. NovaPlus, Petrofree, Petrofree LE were C14,C16,C18, C20 mixes. Current use of ‘fillers’ makes filtrates more ‘complicated’. These are now multi-component fluids in the C7-C30 range and this makes corrections more difficult.
Tahiti Field: OBM contamination corrections
OBM Contamination effects:
Pour point decreases for some oils
Wax appearance point decreases slightly (may be within meas. uncertainty)
Saturates increase (n-Paraffins)
Asphaltenes become more stable
Dew point and bubble point decrease
GOR decreases
Liquid density generally decreases
Viscosity increases

13. How clean does it need to be? For Black Oils:
PVT relationships, Density, GOR
No analogs: Target 5% OBM
Analogs available: Target 10% OBM, preferably <5% OBM. These properties can be modeled with some confidence up to 20% OBM. However, note that many labs have difficulty quantifying OBM contamination amounts above 15% OBM.
Tahiti Field: Fluid modeling of OBM contamination effects by Kathy Greenhill and Jeff Creek
Volumetric Properties readily corrected (Rs, Bo, Do)
Saturation Pressure correction difficult (Pob, Pod)
Viscosity
Correction for OBM complicated
Experimental error with perfect sample is +/-15%.
Consider making several determinations with different OBM amounts
Flow Assurance
Wax appearance typically invariant up to 25% OBM
Asphaltene Onset Pressure variation can be significant above 10% OBM.

14. How clean does it need to be? For Black Oils:
Bulk fluid properties (viscosity, emulsions, assays)
Volumetric property correction for contamination is generally straightforward.
Affect on emulsions and rheology are less predictable and typically require physical testing.
Geochemistry
OBMs alter Vitrinite reflectance, TOC, density, isotopes, SARA and biomarkers.
For Black Oils, high definition studies work best when less than 10% OBM. Recent results indicate much improved results below 5% OBM.
Useful information can be obtained up to 30% OBM contamination.
For Light Oils and Gas Condensates:
OBM contamination may interfere with critical light components making the acquisition of cleaner samples necessary. For difficult sampling operations, a well test may be required.

15. What's the best way to get the sample we need
What's the best way to get the sample we need? (highest Possibility of Success, Lowest Cost)
Determine what is the likely pump-out duration
What is the overbalance?
What is the mud system (invasion profile)?
What is the expected formation / fluid mobility?
What is the anticipated fluid type (viscosity and GOR)?
Determine sampling strategy
Plan pump-out until we get to below 5% OBM contamination? Would 10% OBM be acceptable?
Consider setting maximum pump-out time (5 to 8 hours?)
Consider contingency plan
How long to pump at one station before moving?
How many attempts will be made?

16. What's the best way to get the sample we need
What's the best way to get the sample we need? (highest Possibility of Success, Lowest Cost)
Define Risk:
Determine probability of getting tool differentially stuck
How long has the hole been open?
What is the well angle to the angle of formation bedding dip?
What is the mud system?
What is the overbalance pressure?
Indicators
Did the drill pipe take any drag on the trip out?
What does the caliper show? Does the hole have ledges or breakouts? Hole geometry is your biggest concern!
Determine the probability of getting line stuck (key seated)
What is the dog leg severity of the hole above the sampling interval?
How much formation is open above the sampling interval?
What is the overbalance in these shallower zones?

17. What's the best way to get the sample we need
What's the best way to get the sample we need? (highest Possibility of Success, Lowest Cost)
VOI Example: Knotty Head Exploration Sampling
Exploration prospect, some well sampled zones, some under sampled zones Developed sample acquisition hierarchy, sampling fluids in sidetrack.
Strategy – pump-out until <5% OBM contamination
Conditions… **
Successful fish
$3.1 Million
Yes
Fish or no Fish
* Loss of wellbore for further Data acquisition
Yes No
Tool Stuck *
$4.3 Million
Sampling Strategy
** Would you do a VSP or RSWC ops in the same hole you just fished?
Yes No *
$1.7 Million
MDT tool selection
<5%OBM No
$0.5 Million
MRPQ
Off wall after 6hrs
$0.35 Million
Decision
Uncertainty
Norm probe

18. Chevron/Schlumberger Compartmentalization Study using Downhole Fluid Analysis at Tahiti
Chevron provided both live and dead M21 Sand oil samples and the conceptual geologic framework models for each sand.
Schlumberger conducted Lab VIS-NIR (using the world’s best mass spectrometer at Florida State University) and fluorescence spectroscopy (with Wood’s Hole Oceanographic Institute) on live and dead oil samples, then compared the results with field Downhole Fluid Analysis optical data.
The Team successfully defined the asphaltene gradient in the oil column and tested for compartmentalization. We found small variations in GOR but large variations in Color that correlate very well with SARA Asphaltene content. Also, we found that the two-fold variation in color is a reflection of an asphaltene gradient in the oil column. The M21A and B Sands had different trends, but no clear indication of lateral compartmentalization was found.

19. Stratigraphy and Structure
Tahiti Field:
Compartmentalization Analysis N S
Stratigraphy and Structure
Pressures
Fluid Properties
Oil Geochem
Solution Gas Geochem
Mud Gas Isotopes
All these methods all seem to agree that for the main Tahiti reservoir, compartments either do not exist or are limited to “baffles”
After the field came on production in April, 2009 interference was seen between all six wells within about 12 days

20. Tahiti Asphaltene Concentration Model
Schlumberger: Nicolas Ebele, Sandra Quental, Francois Dubost, Soraya Betancourt
PS03
PS003
Asphaltene Content %w/w
PS002
640#2 ST1 BP1 -
640#2 ST0 BP2
Dz=1870’
a=45o +
M21A
Existing Wells
640#2 ST1 BP1
640#2 ST0 BP2
M21B
New Wells
PS002
PS003
Calibrated model with existing wells
Predict DFA Optical Densities and Asphaltene Concentration in new wells drilled updip N

21. Sampling Best Practices
1) Early Involvement in sample planning!!!
Try to influence mud selection and encourage minimum overbalance. Overbalance influences pump selection and pump stroke volume (which can lead to significantly longer pumpout times to displace the same volume).
Set casing over any low pressure sands, if practical. If not practical, consider conducting contingent wireline runs prior to reaching TD.
Quartz pressure gauges are very accurate. Depth control isn’t. Plan accordingly.
2) Consider likely mobility and possible pump out times.
In general, OBM contamination is directly proportional to pumpout volume. Real-time optical analyzers are necessary to develop a feeling for sample quality and determine that pumpouts are proceeding as planned. Don’t waste rig time.
Make sure you capture a set of relevant OBM samples.
3) Construct sampling strategy and consider the probability of tool sticking.
Consider tool selection and string weight. Build a flexible plan. Monitor drilling and consider how changing hole conditions may change risk leading up to job.
Define back-off points as clearly as possible before the job and have a clear chain of command relationship defined with Drilling.
4) Immediately after the job, QA/QC the data and properly archive the run.

22. Notable References for further reading:
Brown, Alton “Improved Interpretation of Wireline Pressure Data” AAPG Bulletin, v. 87 No 2 (February 2003), pages
Brooks, A., Wilson, H., Jamieson, A., McRobbie D.,Holehouse, S.G., “Quantification of Depth Accuracy”, Paper SPE presented at the 2005 SPE Annual Technical Conference and Exhibition, Dallas, TX, U.S.A., 9-12 October.
Hashem, M., Elshahawi, H., Ugueto, G., “A Decade Of Formation Testing – Do’s and Don’ts and Tricks of the Trade”, SPWLA Paper L, presented at the SPWLA 45th Annual Logging Symposium Noordwijk, The Netherlands, 6-9 June, 2004.
Kabir, C.S., Pop, J.J., “How Reliable is Fluid Gradient in Gas/Condensate Reservoirs?”, Paper SPE 99386, presented at the SPE Gas Technology Symposium held in Calgary, Alberta, Canada, May 14-17, 2006.
Lee, J., Michaels, J., Shammai, M., Wendt, W., “Precision Pressure Gradient Through Disciplined Pressure Survey”, SPWLA Paper EE, presented at the SPWLA 44th Annual Logging Symposium, Galveston, Texas, U.S.A., 6-9 June, 2003.
Mullins, Oliver C., Betancourt, Soraya S., Cribbs, Myrt E., Creek, Jefferson L., Dubost, Francois X. Dubost, Andrews, A. Ballard and Venkataramanan, Lalitha, “Asphaltene Gravitational Gradient in a Deepwater Reservoir as Determined by Downhole Fluid Analysis” SPE presented at the SPE International Symposium on Oilfield Chemistry held in Houston, Texas, U.S.A., 28 February–2 March 2007.
Charles Collins, Mark Proett, Bruce Storm and Gustavo Ugueto, “An Integrated Approach to Reservoir Connectivity and Fluid Contact Estimates by Applying Statistical Analysis Methods to Pressure Gradients”, paper presented at the SPWLA 48th Annual Logging Symposium held in Austin, Texas, USA, 3-6 June, 2007.
Elshahawi, M. Hashem, D. McKinney and M. Flannery, Shell, L. Venkataramanan and O. C. Mullins, Schlumberger, “Combining Continuous Fluid Typing, Wireline Formation Tester and Geochemical Measurements for an Improved Understanding of Reservoir Architecture”, SPE , paper presented at the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, U.S.A., September.
Elshahawi, H., Samir, M., Fathy, K.,, “Correcting for Wettability and Capillary Effects on Formation Tester Measurements”, SPWLA Paper R, presented at the SPWLA 41st Annual Logging Symposium, June 4-7.
Asphaltenes, Heavy Oils, and Petroleomics, Oliver Mullins, et al. (eds.), Springer, 2007