Presentation on theme: "SPWLA WFT SIG Houston, Texas September 27, 2011"— Presentation transcript:
1SPWLA WFT SIG Houston, Texas September 27, 2011 Compartments for Beginners: Wellbore Formation Testing in the Real WorldSPWLA WFT SIGHouston, TexasSeptember 27, 2011
2Why are we talking about this? What has been the outcome of the last few years of data collection?Compartments, Compartments and … more CompartmentsHow do we define the Value Proposition?Importance of Sample Quality and VolumeValue of Information vs cost and riskHow do we plan and run the job?Practical tips for adding value with new technology
3The deepwater Appraisal problem: Reduce Subsurface Uncertainty in a cost-effective manner Industry moving towards:Ultra deepwater, deeper objectivesNon-amplitude and subsalt prospectsLess forgiving smaller targetsAppraisal problem is getting more difficultIncreased subsurface uncertaintyHigh 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 wayCombining 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
4GOOD UGLY 2009 DEEPSTAR 9702 Appraisal Lookback: 28 DWGOM Fields Two fields significantly outperformed expectationsSix fields significantly underperformed expectationsOf the remaining 22 fields 75% marginally underperformed and 25% marginally outperformedIn general, fields showed more complexity than anticipatedBAD RESERVES OUTCOMEGOODUGLYBAD PRODUCTION OUTCOME
6Looking for Value Why are we talking about this? Optimize Cost and Maximize ValueApply Appropriate FELFor a new field discoveryUncertainty Management PlanAssess the impact of fluids properties on project executionImpact of compartments on Appraisal programCompartmentsFluidsImpactIMPACTExploration: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?
7Compartments, 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), andA review of geochemical marker results.Oil FingerprintingMud gas Isotope AnalysisSolution Gas Isotope AnalysisSulfur Isotope AnalysisReal-time techniques that are useful in the timeframe needed to make decisions to complete or sidetrack are limited.
8Courtesy Arild Fossa, PowerWell Services Exploration and Appraisal Activities Data Collection and Integration Toolkit1 cm1 m1 kmGEOLOGYSEISMICStaticCORESLOGSNEW PARADIGM: THE DISTRIBUTION OF PRESSURE AND FLUIDS IN THE RESEVOIR REPRESENTS A TYPE OF DYNAMIC DATA!Distance ofinvestigationWFT PRESSURESFLUID PROPERTIES & GEOCHEMISTRYDynamicWELLTESTTRACERS10-2 m10-1 m1 m10 m102 m103 m104 m
9In 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 architectureFilling history as an indication of geologic complexityProximity to fluid contacts and gravitational gradingBiodegradation, tar mats, loss of light ends and mixing eventsand allow production allocation or mechanical troubleshooting with fingerprintsWater Samples: (500 to 1,000 cc per zone)Hydrate formation, Scale, Souring and Corrosion potential, SalinityTahiti Field: Four conventional cores, over 500 pressure points, 33 fluid samples, M-21 Well TestOWC3 milesGeochemical allocation of fluids during the Tahiti Well Test by Russ Kaufman and Stan TeermanRelationship of optical density during Tahiti sample pumpouts with column height by Soraya Betancourt (SLB)
10In 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 evaluationSamples compromised during transfer or leakage during storageCustody transfer and inventory mistakesMultiple measurements required for confidenceStudies that usually require substantial volumes of oil (gallons, barrels):Restored state core floods for SCALCompletion/stimulation fluid compatibilityFlow loop testingEmulsions key for oils <20 deg APILarger 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. WilliamsDeepwater 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.
11In 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, viscosityVolume: 1,000 cc Res Fluid / zone affect OOIP, rate and recoveryGeochemistry fingerprinting: Reservoir continuity and variabilityVolume: 50 cc STO / zone Source rock typing, analogsHydrates, wax & asphaltene potential: Operability, cost,Volume: 100 to 200 cc Res Fluid / zone development optionsCrude Value: Market Value, STO propertiesVolume: 10 gallons STO / zone and character, refinery optionsEmulsion / Foaming: Viscosity variation with water cut;Volume: 10 gallons STO / zone separation time; foam stabilityChemical Screening: Effectiveness ofVolume: 10 gallons STO select chemicals
12Tahiti Field: OBM contamination corrections How clean does it need to be? Oil Based Mud ContaminationOil-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 correctionsOBM Contamination effects:Pour point decreases for some oilsWax appearance point decreases slightly (may be within meas. uncertainty)Saturates increase (n-Paraffins)Asphaltenes become more stableDew point and bubble point decreaseGOR decreasesLiquid density generally decreasesViscosity increases
13How clean does it need to be? For Black Oils: PVT relationships, Density, GORNo analogs: Target 5% OBMAnalogs 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 CreekVolumetric Properties readily corrected (Rs, Bo, Do)Saturation Pressure correction difficult (Pob, Pod)ViscosityCorrection for OBM complicatedExperimental error with perfect sample is +/-15%.Consider making several determinations with different OBM amountsFlow AssuranceWax appearance typically invariant up to 25% OBMAsphaltene Onset Pressure variation can be significant above 10% OBM.
14How 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.GeochemistryOBMs 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.
15What'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 durationWhat 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 strategyPlan 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 planHow long to pump at one station before moving?How many attempts will be made?
16What'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 stuckHow 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?IndicatorsDid 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?
17What'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 SamplingExploration prospect, some well sampled zones, some under sampled zones Developed sample acquisition hierarchy, sampling fluids in sidetrack.Strategy – pump-out until <5% OBM contaminationConditions…**Successful fish$3.1 MillionYesFish or no Fish* Loss of wellbore for further Data acquisitionYesNoTool Stuck*$4.3 MillionSampling Strategy** Would you do a VSP or RSWC ops in the same hole you just fished?YesNo*$1.7 MillionMDT tool selection<5%OBMNo$0.5 MillionMRPQOff wall after 6hrs$0.35 MillionDecisionUncertaintyNorm probe
18Chevron/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.
19Stratigraphy and Structure Tahiti Field:Compartmentalization AnalysisNSStratigraphy and StructurePressuresFluid PropertiesOil GeochemSolution Gas GeochemMud Gas IsotopesAll 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
20Tahiti Asphaltene Concentration Model Schlumberger: Nicolas Ebele, Sandra Quental, Francois Dubost, Soraya BetancourtPS03PS003Asphaltene Content %w/wPS002640#2 ST1 BP1-640#2 ST0 BP2Dz=1870’a=45o+M21AExisting Wells640#2 ST1 BP1640#2 ST0 BP2M21BNew WellsPS002PS003Calibrated model with existing wellsPredict DFA Optical Densities and Asphaltene Concentration in new wells drilled updipN
21Sampling 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.
22Notable References for further reading: Brown, Alton “Improved Interpretation of Wireline Pressure Data” AAPG Bulletin, v. 87 No 2 (February 2003), pagesBrooks, 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