geological and engineering challenges in estimating petroleum reserves

6 / December 2009—February 2010Reservoir Solutions

Vol. 12, No. 4

Performing some 800 reserves studies annually forhundreds of oil and gas companies, Ryder Scott person-nel see a wide variety of internally produced petroleumreserves estimates. By in large, most estimates areprepared by qualified reservoir engineers and geoscien-tists.

However, over the years, Ryder Scott has noticedcommon technical errors in the preparation of re-serves estimates aside from any definitional or judg-mental issues. This multipart article will offer guide-lines to help reduce the chance of errors ingeoscientific and engineering analysis.

The geoscience component forms the basis forengineering estimates. Ryder Scott has noticedrecurring errors in geological evaluations involvingstructure and isopachous maps, downdip limits andattic volumes. This first newsletter article focuses onstructure maps.

Geological and engineering challenges in estimatingpetroleum reserves — Part I: Structure maps

Ryder Scott has noticed commontechnical errors ...aside from anydefinitional or judgmental issues.

Editor’s Note: This revised excerpt from “Oil and GasReserves Estimates: Recurring Mistakes and Errors,”(SPE Paper No. 91069), was first published five yearsago in our newsletter. This first part of the reprintseries is now republished at the request of our readers.The material and issues are as relevant now as whenthe paper was written by reserves evaluators RonHarrell, John Hodgin and Thomas Wagenhofer then atRyder Scott. To order a copy of the full paper, go towww.onepetro.org, a multisociety, Web-based library.

Common mistakes in structure mapsA geologist selects structure-map surfaces repre-

senting the top and base of a contributing reservoir toassist in determining a volumetric estimate. Theprocess involves combining surface-mapping informa-tion with lateral limits from structural and strati-graphic barriers and downdip fluid limits to describe aproductive reservoir area.

Structure on top surfaceStructure on top surfaceStructure on top surfaceStructure on top surfaceStructure on top surface—A common error istying structure maps to well-pick or seismic-attributemarkers that don’t represent the top of the contribut-ing reservoir. This results in overstating the produc-tive area and reserves.

Figure 1 shows an overstatement of reservescaused by picking a marker from well data to repre-sent the structural surface at the top of the reservoir.Note a 50-ft elevation difference between the -7000-ftmarker top and the -7050-ft top of the effective pay.

This exaggerates the areal extent, which is basedon the projected downdip limit to the top of thereservoir. The magnitude of the error increases as thedistance between the mapping points and structuraldip increases.

Figure 1. Top-surface mapping error using marker instead oftop of effective pay.

Similarly, Figure 2 shows the selection of a map topcorresponding to the top of the formation rather thanthe top of the effective reservoir section. Like theprevious example, the selection of a correlativemapping point results in a similar exaggeration of theareal extent and overstates the reserves.

Figure 2. Top surface mapping error using top of formationinstead of top of effective pay.

These errors are also replicated when the top of aseismic event is not adjusted to tie with the top of thecontributing reservoir unit as determined from welldata.

Structure on basal surfaceStructure on basal surfaceStructure on basal surfaceStructure on basal surfaceStructure on basal surface—Structure mapstied to markers (well or seismic) on the base of aformation that does not represent the base of thecontributing reservoir may result in the following: Overstating the gross rock volume.

December 2009—February 2010 / 7Reservoir Solutions

Vol. 12, No. 4

Inaccurately determining the inner limit of the fullnet thickness used in constructing net pay isopachousmaps.

Common mapping practice relies on the calcula-tion of gross rock volume generated by the differencebetween structural surfaces (or maps) on the top andbasal surfaces of the reservoir. The intersection of thefluid contacts on the top and basal surfaces determinesthe gross rock volume of the reservoir.

Figure 3 shows the overstatement (crosshatchedarea) of the productive gross rock volume using amarker picked from well data to represent the struc-tural surface at the base of the reservoir. In thisillustration, the gross interval thickens in the updipdirection. The discrepancy becomes greater as thedistance between the mapping points increases.

Figure 3. Overstatement caused by selecting marker as baseof formation instead of base of effective pay.

Figure 4 illustrates an error in the determinationof the inner limit of water. The error is caused byinaccurately selecting the base of the contributingreservoir unit. The volume within the wedge area isoverstated and the volume above the inner limit isunderstated.

This results in an understatement of reserves.The discrepancy increases as the distance betweenmapping points increases. A decrease in structural dipwould further compound this problem.

Figure 4. Error of inner water limit caused by incorrectlypicking base of effective pay.

These errors are also replicated when the base of aseismic event is not adjusted to tie with the base of thecontributing reservoir as determined from well data.

Position of faults relative to the structurePosition of faults relative to the structurePosition of faults relative to the structurePosition of faults relative to the structurePosition of faults relative to the structureon top surfaceon top surfaceon top surfaceon top surfaceon top surface—Faults not tied to the structure mapon the top surface of the contributing reservoir mayoverstate or understate productive area, associated

Figure 5. Error in picking fault location caused by incorrectlyselecting marker as top of structure.

Once again, factors, such as the distance betweenmapping points, the structural dip and thickness of thereservoir unit and the dip on the fault plane, deter-mine the magnitude of the error.

volume and reserves.Figure 5 demonstrates an error caused by linking

the position of the updip trapping fault to the top ofstructure based on a marker rather than the top of theeffective reservoir.

Ryder Scott has re-leased Version 5 of itspopular Reservoir Solu-tions software, which iscompatible with Excel2007. The programs areavailable for downloadat www.ryderscott.com.The new programs alsoare compatible with pre-vious versions of Excel

from 97 through 2003. Developer James LathamJames LathamJames LathamJames LathamJames Latham,senior vice president, said that CD versions of thenew software will be available soon.

Ryder Scott has also introduced a new compila-tion, The Works, which is a single Web site down-load comprising all ten applications. “This ‘suite’simplifies installation and will be a real time saverfor our users,” said Latham.

The “Download, Installation and Startup Instruc-tions” page on the Web site documents importantaspects of getting started with the software in bothExcel 2007 and previous versions with a special em-phasis on security settings and the new open XMLfile formats in Excel 2007. Computations made withprevious versions of Reservoir Solutions softwareare not compatible with the new version.

Reservoir Solutions now works with Excel 2007

6 / March—May 2010Reservoir Solutions

Vol. 13, No. 1

Editor’s Note: This is a revised excerpt from “Oil andGas Reserves Estimates: Recurring Mistakes andErrors,” (SPE Paper No. 91069). To order a copy of thefull paper, go to www.onepetro.org.

Ryder Scott personnel see a wide variety ofinternally produced petroleum reserves estimates andmost of them are well prepared. However, the firmhas noticed common technical errors in reservesestimates.

This multipart article offers guidelines to helpreduce the chance of errors in geoscientific andengineering analysis. This second newsletter articlefocuses on downdip limits and isopachous maps.

Downdip limits in vertically stratified reservoirsThe down-dip extent of a productive area is defined

by fluid contacts and lateral limits from structural orstratigraphic barriers. Assuming vertical communica-tion and a common downdip contact in stratified orlayered reservoirs without adequate support frompressure data is likely to result in an overestimation ofin-place volumes.

Figure 6 illustrates a log section marked toindicate three porous intervals shown as A, B, and C.These three zones, all assumed to be capable ofcommercial production, may be part of a single pres-sure-connected reservoir or may collectively comprisethree separate reservoirs. Well data alone may notresolve this uncertainty.

Isopachous mapsThe estimation of volumetric reserves depends on

three main types of isopachous maps: (i) map of grossthickness of reservoir unit, (ii) map of net effectivethickness generally based on application of a minimumporosity cutoff value, and (iii) map of net effective paythickness generally based on the application of amaximum saturation cutoff value.

Figure 7 illustrates the two main regions of a netpay isopach map; the wedge zone and the area ofmaximum fill-up.

Technical challenges in estimating reservesPart 2: Downdip limits and isopachous maps

The cross section in Figure 6 illustrates thedifference between the productive volume of the threezones with a common downdip contact (lowest knownhydrocarbon or LKH)—represented by cross-hatchedand shaded (yellow) areas—and those same shadedareas in each zone with separate LKHs.

Most reserves definitions require that the evalua-tor, in estimating proved reserves, assume that thethree reservoirs have separate downdip limits, ifadditional data does not contradict this.

Figure 6. Potential error—Assuming a common downdipcontact in a stratified reservoir

Net pay isopach maps—Downdip wedge zoneNet pay isopach maps—Downdip wedge zoneNet pay isopach maps—Downdip wedge zoneNet pay isopach maps—Downdip wedge zoneNet pay isopach maps—Downdip wedge zone—Thewedge zone in Figure 7 defines the rock volume inareas where the fluid contact intersects the reservoirtop and base. The correct placement of contoursrepresenting net pay thickness in the wedge zone isgoverned by the rate of structural gain above theelevation of the downdip fluid contact and the verticaldistribution of net pay.

A common technique in both hand-drawn andcomputer-aided mapping involves the use of a net-to-gross ratio to represent the change in vertical net payproportionate to the change in elevation above theintersection of the fluid contact and the structure onthe top of the effective reservoir unit. A net-to-grossratio based on the net pay thickness of the reservoirunit to its gross thickness represents an averagedistribution for the entire interval.

In zones where the vertical distribution of net payis fairly constant, average net-to-gross ratio may be afair representation. However, the use of that ratio in areservoir where the net-pay distribution varies overthe vertical interval is unlikely to be correct.

This misapplication may lead to overstating orunderstating reservoir volumes and associated re-serves. The next article, Part 3 in June, will displaythree figures illustrating the relationship between net-to-gross ratios and reservoir volumes and providemore information on isopach mapping.

Figure 7. Illustration of wedge zone and area of maximum fill-up

6 / June—August 2010Reservoir Solutions

Vol. 13, No. 2


Ryder Scottpersonnel see awide variety ofinternally producedpetroleum reservesestimates and mostof them are wellprepared. How-ever, the firm hasnoticed commontechnical errors inreserves estimates.

This multipartarticle offers guidelines to help reduce the chance oferrors in geoscientific and engineering analysis. Thisthird newsletter article focuses on isochore maps(Cont. from Part 2, March 2010 Reservoir Solutions)and attic volumes.

Net pay isochore maps—Downdip wedge zone Net pay isochore maps—Downdip wedge zone Net pay isochore maps—Downdip wedge zone Net pay isochore maps—Downdip wedge zone Net pay isochore maps—Downdip wedge zone (Cont.from Part 2)—The use of an average net-to-gross ratioin a reservoir where the net-pay distribution variesover the vertical interval will likely lead to misstatingreserves. The following three figures illustrate therelationship between net-to-gross ratios and reservoirvolumes.

The net-to-gross ratio for the well illustrated inFigure 8 is 0.50. However, most of the net pay occursin the upper 20 ft of the 80-ft gross interval.

Technical challenges in estimating reservesPart 3: Isochore maps and attic volumes

Figure 10 illustrates a net pay isochore mapconstructed using the relationship of net pay thicknessto height above the downdip fluid contact. In thisexample, the net pay isochore volume in Figure 9 is 18percent smaller than the volume in the correct mapfrom Figure 10.

Figure 9 illustrates a net pay isochore map con-structed using the average net-to-gross ratio of 0.50 inthe wedge zone.

Figure 8. Example of a well log from a reservoir where most ofthe net pay occurs near the top. Structure map with welllocations also shown.

Figure 9. Illustration of net pay isochore with a wedge zonemapped using average net-to-gross approach.

Figure 10. Same data mapped with wedge zone based oncorrect application of a vertical net-to-gross ratio.

Net Pay Isochore0.50 Net/Gross

Net Pay IsochoreSand Developmentat Top of Reservoir

June—August 2010 / 7Reservoir Solutions

Vol. 13, No. 2

A similar but inverse erroroccurs if the vertical net paydistribution is inverted from thatshown in Figure 8. In this case, amap constructed using the averagenet-to-gross ratio overstates theproductive reservoir volume.

In both examples, the “average”net-to-gross approach results inmechanically equal-spaced thicknesscontours in the wedge zone whichdo not represent the verticaldistribution of net pay in the well.

Net pay isochore maps—ThicknessNet pay isochore maps—ThicknessNet pay isochore maps—ThicknessNet pay isochore maps—ThicknessNet pay isochore maps—Thicknesswithin area of maximum fill-upwithin area of maximum fill-upwithin area of maximum fill-upwithin area of maximum fill-upwithin area of maximum fill-up—The area of maximum fill-up asillustrated in Figure 7 (in March2010, Reservoir Solutions newslet-ter, Page 6) is the region updip fromthe intersection of the fluid contactand the structure on the base of theeffective reservoir unit. Above thisinner limit of fluid, the placement ofnet pay thickness contours isgoverned by the lateral change inthe net effective reservoir thick-ness.

A common shortcut used incomputer-aided mapping calculatesthe gross rock volume from thevertical difference between the topand base of the reservoir. Net paythickness is generated by applying anet-to-gross ratio to the gross rockvolume. A few of the potentialinherent errors are as follows: Use of an arithmetic average ofthe net-to-gross ratio from multiplewell penetrations may not representlateral variation from well to well.A more rigorous approach is torepresent the lateral variation bycontouring the net-to-gross ratiofrom well data. The resultinginterpolated distribution of net paythickness should tie or be adjustedto match the well-data points.Evaluators should consider thevalidity of estimates of interpolatednet-to-gross ratios greater than themaximum value obtained from welldata. As previously noted, errors inthe selection of the top or base ofthe contributing reservoir unit willresult in overestimating the grossinterval thickness and gross rockvolume. The interpolated lateraldistribution of the gross reservoirthickness should tie to or beadjusted to match actual well-datapoints. When the top or base of thereservoir unit is based on seismic

data, the evaluator should consider the quality and resolution of seismicdata. The evaluator should also consider the validity of estimates ofinterpolated gross reservoir thickness greater than the maximum valueobtained from well data. Similarly, consideration should be given to the validity of lateralvariations in interpolated net pay thickness derived from uncalibratedseismic amplitudes that result in values greater than indicated by theactual well-data points.

Attic volumesFrequently, evaluators assign reserves to volumes updip to the last

well penetration point in a reservoir. The level of confidence in thestructural and stratigraphic continuity of the reservoir and recognition ofthe appropriate drive mechanism are critical to correctly attributingreserves.

Figure 11 shows net pay thickness projected in association withstructural gain only and exceeding the maximum net effective sandthickness updip to the wedge zone from the downdip well penetration.

Figure 11. Potential error in estimating attic volumes based on projecting structuralgain greater than maximum sand thickness.

Evaluators must consider the level of confidence in the position of faultsand stratigraphic conditions away from the existing subsurface well control.Seismic fault placement should be collaborated by subsurface well control.Stratigraphic continuity verified in zones above or below the interval inquestion increases the level of confidence for the attribution of reserves.

Though not necessarily a geoscience issue, evaluators must considerthe possibility of a gas-saturated attic above a highest-known oil limit. Theymust also consider that in a water-drive reservoir, the attic volume may notbe recovered from existing wells.

Regulators in Canada expect tofinalize approvals by August orSeptember and publish the newamendments in September orOctober. The effective date will bein late December. The CSA will notrequest further comments but willprovide responses to those received.

David ElliottDavid ElliottDavid ElliottDavid ElliottDavid Elliott, chief petroleumadvisor to the ASC, said, “We do notexpect the amendments to have a

significant effect on the preparationof evaluation reports, but theycould, in some circumstances, havean effect on the preparation ofdisclosures.”

Seven companies responded inmid to late March through com-ment letters on the proposedamendments to NI 51-101. Industrycomments were published by theASC in mid May atwww.albertasecurities.com.

Canada—Cont. from Page 1

4 / September—November 2010Reservoir Solutions

Vol. 13, No. 3



This multipart article offers guidelines to helpreduce the chance of errors in geoscientific andengineering analysis. This fourth newsletter article inthe six-part series focuses on decline-curve analysisand operating costs.

Technical challenges in estimating reservesPart 4: Production decline curves, operating costs

Production decline curvesPerformance decline analysis is the most common

technique to estimate reserves in mature fields whereample performance data is available for both primaryand secondary products. Besides the obvious subjectiv-ity in determining a decline trend, common errors areassociated with composite field decline curves andneglecting to apply a minimum hyperbolic decline rate.

Composite field production decline curvesComposite field production decline curvesComposite field production decline curvesComposite field production decline curvesComposite field production decline curves—Quite often,an engineer only has production histories for a multi-well lease, production unit, single reservoir or entirefield. Individual well-production histories may not beavailable or can be compiled only through the use ofallocations relying upon less-than-perfect well tests.When an aggregate well-production history is displayedas a graph of monthly oil or gas production, thehistorical trend may show a continual decline overtime.

Indeed, this trend may be well defined as anexponential or hyperbolic decline that can be projectedinto the future with a reasonably high degree ofreliability based upon the mathematical “best fit” of thehistorical data. This is illustrated as Figure 12.

This projectionclearly presents anappealing case for usingthe entire productionhistory to obtain anestimate of provedreserves.

Such a declineprojection may beacceptable, however,only under the followingconditions: Well count isrelatively stable. Production condi-tions and methods arelargely unchanged overthe producing life. Wellbore interven-tion and other remedial

work can be classified solely as maintenance.If these rather stringent conditions are not met,

reliance upon this projection to estimate provedreserves may be inappropriate.

Figure 13 has the same production decline curveas Figure 12 but contains additional plotted datareflecting the number of producing wells over theproductive life of the field. Often overlooked, thisadded information has a significant effect on theprevious interpretation of remaining proved reserves.

Clearly, the forecast in Figure 12 is not achievablewithout the continual drilling of additional wellsachieving similar, positive results, a highly unlikelycondition in most cases. Frequently, estimators usethis erroneous approach to estimate proved producingreserves.

In some cases, evaluators compound their mis-takes by adding yet even more proved undevelopedreserves assigned to discrete drilling locations.

Figure 13. Field forecast based on apparent trend with wellcount.Figure 12. Field aggregate forecast based on apparent trend.

September—November 2010 / 5Reservoir Solutions

Vol. 13, No. 3

In preparing a forecast such as that in Figure 14,which restates the data in figures 12 and 13 based onaverage monthly production per well, an evaluatorshould be cautious when using “average well” projec-tions.

rates and cash flows provide an option to use a hyper-bolic projection with a specified N-factor and finaldecline rate. This N-factor can also be calculated byusing the curve-fitting function of the economic soft-ware program.

Allowing the software to default to an unspecified,final decline rate, which is often unreasonable andunsupportable, may have little effect on present value.However, the “added” reserves frequently cause grossoverestimations. A review of depleted or nearlydepleted area analogs will often guide the selection ofan appropriate final decline rate.

Other errors with decline-curve analysisOther errors with decline-curve analysisOther errors with decline-curve analysisOther errors with decline-curve analysisOther errors with decline-curve analysis Ultimate recovery not related to volumetricestimates. Apparent decline trends combined withrelatively flat flowing-tubing pressures can lead tooptimistic reserves estimates, particularly in gasreservoirs with partial to strong water drives. Assuming exponential decline in reservoirs thattend to exhibit hyperbolic decline trends (source ofunderestimating reserves). These include (i) tight gasreservoirs (enhanced if multiple layers), (ii) naturallyfractured reservoirs, and (iii) waterflood reservoirs. Conversely, assuming a hyperbolic decline may leadto overstating reserves in cases where an exponentialdecline would also fit performance.

Guidelines to reduce mistakes in decline-curve analysisGuidelines to reduce mistakes in decline-curve analysisGuidelines to reduce mistakes in decline-curve analysisGuidelines to reduce mistakes in decline-curve analysisGuidelines to reduce mistakes in decline-curve analysis Always attempt to estimate performance decline ata well or completion level for best results. Include trends in secondary products (condensateyields, gas-oil ratios, water cuts) in analysis. When projecting group- or field-level rates, makesure to review the components of the field curve andproperly account for well work and associated costs thatare required to maintain the decline trend. If wellwork cannot be sustained, the field curve needs to beadjusted to fit the true decline of existing wells. Use analogous fields or more mature wells in thefield or area to establish typical decline behavior,including minimum hyperbolic decline rates. Gain an understanding of reservoir properties —porosity, permeability, lithology and depositionalenvironment — to exercise better judgment in select-ing exponential vs. hyperbolic decline models. Attempt to combine various types of evaluationtechniques with decline-curve analysis to assureconsistency in results.

Operating costsOperating costs reflect expenses attributable to the

daily operations of a field and typically do not includegeneral and administrative expenses or other overheadcosts. Operating costs are used to capture expenses,which affect reserves values, and to estimate economiclimits, which affect reserves volumes. The economiclimit is defined as the rate and time at which revenuefrom production becomes less than the cost of opera-tions.

Typical errors or mistakes associated with operat-ing costs include the following: (i) use of forecasted orbudgeted operating costs that are lower than actual

The average well production, which is determinedby dividing the field production by the well count, mayhave been sustained by the continuing impact ofproduction from new wells and well-maintenancework.

Figure 15 presents a final forecast without theeffects of drilling and single-event workovers on thefield trend. The final projection may yet overstateremaining reserves unless the evaluator can beassured of future opportunities for re-completions,stimulation treatments or other types of productionenhancements.

Figure 14. Alternate forecast based on constant well countand average well performance.

The preferred approach is to rely upon the perfor-mance of individual wells whenever possible. Anyother approach may lead to an optimistic estimate offuture performance and proved reserves.

Make sure to specify minimum decline rates inhyperbolic projections. Virtually all commercialsoftware programs used to forecast future production

Figure 15. Alternate forecast after removing effects of drillingand single-event well-maintenance work.

Please see Operating Costs on Page 6

6 / September—November 2010Reservoir Solutions

Vol. 13, No. 3

Operating Costs—Cont. from Page 5

long-term historic costs,(ii) recurring well orfacility costs that areassumed to be singleevents and thereforeexcluded from futureestimates of cost, (iii)assumption of per unitcost of primary product,dollars per barrel forexample, without theproper treatment offixed cost or costs ofproducing secondaryproducts, and (iv) failureto evaluate changes tocosts caused by theintroduction of new

decline. This increase in unit costs of production isexacerbated by increasing needs for compression andartificial lift and a continuing growth in maintenancerelated to corrosion, equipment repairs, water treat-ment and disposal and ever-expanding environmentalconcerns. An understatement of operating costs willlead to an overstatement of future net income andreserves.

All performance-derived estimates of reserves arelimited by a terminal rate, which is typically describedas an economic limit. A unit cost of oil or gas produc-tion never leads to an economic limit as the cost willsimply remain a fraction of revenue, which illustratesthe improper assumption of a constant unit operatingcost.

Changes in recovery processChanges in recovery processChanges in recovery processChanges in recovery processChanges in recovery process—Problems in operating-cost estimates can also occur if future productioninvolves new recovery mechanisms, for instance, thestart of a waterflood. In such cases, an evaluatorshould conduct a careful review to properly account forchanges in costs resulting from added operationalrequirements.

Guidelines to reduce operating-cost mistakesGuidelines to reduce operating-cost mistakesGuidelines to reduce operating-cost mistakesGuidelines to reduce operating-cost mistakesGuidelines to reduce operating-cost mistakes Future operating costs need to closely agree withobserved historic costs. Incorporate at least two tothree years of lease operating expenses into theestimate of future costs. Attempt to separate costs into fixed and variablecomponents. Include recurring well or facility expenses inoperating cost. Account for changes in costs caused by newrecovery mechanism. Avoid simplification by estimating cost per unitvolume without fixed/variable split. Include cost for handling of secondary products. Apply proper escalation of costs if applicablereserves definitions allow for such.

Editor’s Note: Part 5 to be published in December.

recovery mechanisms.

Projected operating costs are lower than historic averageProjected operating costs are lower than historic averageProjected operating costs are lower than historic averageProjected operating costs are lower than historic averageProjected operating costs are lower than historic averagecostscostscostscostscosts—Occasionally, forecasted or budgeted operatingcosts that are lower than average historic costs areused to estimate reserves. This may be based on anassumption rather than established fact.

This approach, in most cases, will result in over-stating both income and reserves. In general, regula-tory bodies require that operating costs be closely tiedto at least one if not several years of observed costs.Any deviation requires sufficient evidence of circum-stances and events that will lower future operatingcosts.

Recurring well or facility expensesRecurring well or facility expensesRecurring well or facility expensesRecurring well or facility expensesRecurring well or facility expenses—Most reservoirengineers rely on historic facility, lease, and/or welloperating cost statements as the basis for calculatinghistoric operating costs, typically expressed as amonthly cost, for mature properties. This may furtherbe subdivided into fixed and variable components whenappropriate. Historical costs frequently includeexpenses that are deemed to be “non-recurring.”

These costs are typically excluded from averagecosts for use in production forecasts. This approach isacceptable only if the “non-recurring” costs are indeednon-recurring.

All too often, such items as tubing repairs and/orreplacement or periodic platform or facility mainte-nance, are deducted as non-recurring. The failure torecognize the periodic frequency of such maintenancecan lead to an overstatement of reserves and futurenet income.

Assumption of per-unit operating costAssumption of per-unit operating costAssumption of per-unit operating costAssumption of per-unit operating costAssumption of per-unit operating cost—Alternatively, andperhaps of a more serious nature, some evaluators usea future operating cost expressed as a fixed unit costper volume (barrel, mcf or cubic meter) based on theirestimates from a current or past analog. This methoddoes not properly account for variable costs or properinclusion of secondary products.

This approach is virtually never acceptable as unitcosts of production almost universally increase overtime with declining production even if the totalmonthly or annual costs remain constant or slightly

Olds asked, “Has the industry failed to embrace theuse of reliable technology or simply chosen not todiscuss it unless it had a material impact?”

Early adopters take risks. “Pioneers are the oneswith arrows in their backs,” said Olds, quoting a WildWest saying. “Companies may be hesitant to bookreserves using reliable technology if they are uncertainof how to comply with the SEC rule.”

Olds—Cont. from Page 2

“Pioneers are the ones witharrows in their backs.”—Olds

He also said that the survey showed that only four10-K filers reported proved and probable reserves.They were Abraxas Petroleum Corp.Abraxas Petroleum Corp.Abraxas Petroleum Corp.Abraxas Petroleum Corp.Abraxas Petroleum Corp., Dune Energy Inc.Dune Energy Inc.Dune Energy Inc.Dune Energy Inc.Dune Energy Inc.,Tri-Valley Corp.Tri-Valley Corp.Tri-Valley Corp.Tri-Valley Corp.Tri-Valley Corp. and Whiting Petroleum Corp.Whiting Petroleum Corp.Whiting Petroleum Corp.Whiting Petroleum Corp.Whiting Petroleum Corp. Only twocompanies, Newfield Exploration Co.Newfield Exploration Co.Newfield Exploration Co.Newfield Exploration Co.Newfield Exploration Co. and FX EnergyFX EnergyFX EnergyFX EnergyFX EnergyInc.Inc.Inc.Inc.Inc., reported probable reserves without possible.


Vol. 13, No. 4

Editor’s Note: This is a revised excerpt from “Oil andGas Reserves Estimates: Recurring Mistakes andErrors,” (SPE Paper No. 91069). To order a copy of thefull paper, go to www.onepetro.org and access the e-library.


This multipart article offersguidelines to help reduce thechance of errors in geoscientificand engineering analysis. Thisfifth newsletter article focuseson analog-, simulation- andvolumetric-based reservesestimates.

Technical challenges in estimating reservesPart 5: Analogy, reservoir simulation, volumetrics

Inappropriate selection ofanalogs

Engineers and geologistshave historically relied on theuse of analogies to estimateseveral reservoir parametersand performance expectations.An ideal analog is a developedreservoir with well-documentedphysical parameters and anadequate performance historyto rely on for future productionand performance expectations.Such a reservoir is an excellentanalog for predicting thequalities of a nearby undevel-oped reservoir in the sameformation assuming the samedevelopment plan and operatingscenario.

However, given severalpotential analogs in an area,selecting the best-performing reservoir to compare to asubject reservoir is inappropriate. An evaluator shouldanalyze several potential analogs to more fully under-stand the extent and impact of variations in perfor-mance before selecting a reservoir or family of reser-voirs as the analog.

The suitability of a reservoir to be an analog isrelated to the purpose of the comparison. Estimationsof gross rock properties, for example, may be reliablyobtained from comparisons with nearby similar reser-voirs within the same formation. However, ultimaterecovery may vary considerably depending on wellspacing, completion practices and other operationaldetails that affect recovery efficiency.

Evaluators estimate reserves by analogy duringthe early field development stages before definitive

performance and geologic data are available. Con-versely, analogy is frequently used when new recoverymechanisms are introduced to a mature field, forexample, a field undergoing waterflooding, wellstimulation or infill drilling.

The analogy method typically involves the follow-ing three necessary stages: Establish proof of analogy to a mature reservoirand recovery process. Study performance and operations of analogousreservoir.

Apply analogy perfor-mance with appropriateadjustments to account fordeviations to target reser-voir.

Challenges in properselection and application ofanalogs are associated withall three stages, but typicallythe first and third stages arethe most problematic.

Problems with establishingProblems with establishingProblems with establishingProblems with establishingProblems with establishingproof of analogyproof of analogyproof of analogyproof of analogyproof of analogy

In most cases, omit-ting or misinterpreting theeffect of key parameterscauses errors. Proof ofanalogy requires establish-ing geologic/petrophysical,reservoir engineering andoperational similarities.Operational similarity isassured in a scenario wherethe target field is operatedsimilarly to the analogousfield.

The following bulletedsummaries list parametersunder geoscience, engineer-ing and operational areas

that are analyzed to make a case for the analogymethod. Geoscience—Structural configuration, lithologyand stratigraphy, principal heterogeneities, reservoircontinuity, average net thickness, water saturation,permeability, porosity, areal proximity Engineering—Pressure and temperature, fluidproperties, recovery mechanism, fluid mobilities, fluiddistribution, reservoir maturity, well productivity, EORspecifications, areal proximity Operational—Well spacing, artificial lift methods,pattern type and spacing, injector-to-producer ratio,annual injection volumes, fluid handling capacity,stimulation design, areal proximity

For the target reservoir, all parameters have to beas favorable or more favorable than for the analog,

December 2010—February 2011 / 5Reservoir Solutions

Vol. 13, No. 4

especially for a proved reserves classification. Not allitems necessarily apply to each case. The key is toidentify the main performance drivers that will influ-ence the intended, analogous treatment and to deter-mine if similarity can beestablished.

The importance ofareal proximity isemphasized in theSociety of PetroleumEngineers “StandardsPertaining to theEstimating and Audit-ing of Oil and GasReserve Information.”It states, “If perfor-mance trends have notbeen established withrespect to oil and gasproduction, futureproduction rates andreserves may beestablished by analogyto reservoirs in thesame geographic areahaving similar charac-teristics and establishedperformance trends.”

Incorrectly applying analogous performance to thetarget field will cause mistakes in establishing proof ofanalogy and include the following: Assuming similarity because of areal proximity andsame formation without proper evaluation of allparameters. Field not located in same geographic area. No similarity in critical parameters that have beenoverlooked in the analysis. Bias toward trying to force analogy if a few keyparameters match.

Problems applying analogy to target fieldProblems applying analogy to target fieldProblems applying analogy to target fieldProblems applying analogy to target fieldProblems applying analogy to target fieldWhen an evaluator establishes an analogy but key

parameters are slightly different, he may apply theanalogy method by making appropriate adjustments.Inappropriate applications of analogous behavior arecaused by the following: Not designing for operational similarity, particu-larly well density. Not making appropriate adjustments to accountfor operational differences, including costs. Not making appropriate adjustment to account fordifferences in quantified geoscience and engineeringparameters. For example, the evaluator must calcu-late displacement efficiency resulting from differencesin fluid properties or he must account for differences instratification that may affect vertical sweep.

ExamplesExamplesExamplesExamplesExamples When estimating future recovery from a plannedwaterflood by analogy, the evaluator must establishsimilarity between geoscience and engineering param-eters to assure similar displacement and sweepbehavior and design the target waterflood similarly tothe analog for well spacing, pattern type and annual

injection volumes. Operational dissimilarity frequentlycauses overly conservative or aggressive projections. Similarly, differences in mobility may not necessar-ily disqualify an analogy as long as the evaluator

makes proper adjust-ments to account forthe change in displace-ment efficiency.

Guidelines to reduceGuidelines to reduceGuidelines to reduceGuidelines to reduceGuidelines to reducemistakes using analogiesmistakes using analogiesmistakes using analogiesmistakes using analogiesmistakes using analogiesGive preference toanalogies in arealproximity to targetfield.Follow a strictprocess where theevaluator tabulates andcompares key param-eters that need to besimilar.Accept analogyonly if a good matchexists or if adjustmentscan be quantified toaccount for differences.Qualitative or “instinct”

adjustments need to be weighed carefully and may because for downgrading to a lower reserves classifica-tion. Review, and if necessary, design for operationalsimilarity. This will also capture appropriate costs.

Simulation-derived estimates of proved reservesE&P companies manage most significant oil and

gas reservoirsworldwide throughthe use of detailedreservoir models.They are excellenttools for decisionson development,operations andreservoir manage-ment. Dean RietzDean RietzDean RietzDean RietzDean Rietz,manager of reser-voir simulation atRyder Scott, andRyder Scott petro-

leum engineer Miles PalkeMiles PalkeMiles PalkeMiles PalkeMiles Palke have documented theirconcerns about using even the most robust models forproved reserves estimates under given definitions.

They support using simulation of immaturereservoirs to estimate recovery efficiencies and fortesting the ranges of other parameters, includingpermeability and aquifer support. Rietz and Palkefurther recommend that models of mature reservoirsbe used for proved reserves estimates only whenreasonable history matches of the reservoir and wellshave been obtained.

They do not reject reserves estimates based onreservoir simulation. However, Rietz and Palke warn

Please see Simulation on next page


Vol. 13, No. 4

about the dangers of estimating reserves without adetailed review of the model to fully understandassociated assumptions, limitations and applicability.Failure to review the model may cause significantoverstatement of proved reserves.

Failure to incorporate early-life performance datainto volumetric estimates

Early-life production and pressure-decline trendsmay not be sufficiently definitive to provide the solebasis for reserves estimation but should be continu-ously reviewed to fine tune a volumetric-, analogy- orsimulation-derived reserves estimate. Quite fre-quently, this early-life data, including initial rate andpressure data and any available trends, has not beenused to calibrate static estimates until well past thehalf life of a reserves estimate.

Disregarding early performance data and potentialwarning signs may lead to significant positive ornegative reserves revisions. Common errors includethe following: Not revising reserves expectations for undevelopedlocations based on performance data of producingwells. Not anticipating the impact of unexpected increasein water or gas production. Not accounting for effects of pressure depletion onbehind-pipe and infill locations over time.

Updating undeveloped locations based Updating undeveloped locations based Updating undeveloped locations based Updating undeveloped locations based Updating undeveloped locations based on performance dataon performance dataon performance dataon performance dataon performance dataReserves estimated for undeveloped locations at

the beginning of field development are typically basedon drainage area and recovery factor assignmentsfrequently in combination with analogies from nearbyfields. As performance data becomes available, theevaluator needs to review and revise (calibrate)volumetric calculations and recovery-factor estimates.

Deviations from the initial estimates may requireadjustments to recovery factors, rate projections andnumbers and locations of future development wells.Some of the largest errors often occur if existing wellsare adjusted for lower productivity but ultimatereserves are maintained by extending field life.

This situation creates two critical problems.Lower initial rates may indicate lower productivity,thinner pay, interference effects and smaller drainageareas. Therefore per-well reserves and in-placevolumes may be overestimated.

Secondly, capital allocations may be underesti-mated as more wells may be necessary to achieve thepreviously estimated volumes and therefore theresulting net present value will be overstated.

Early or unexpected water production, increases in GOREarly or unexpected water production, increases in GOREarly or unexpected water production, increases in GOREarly or unexpected water production, increases in GOREarly or unexpected water production, increases in GORAn unexpected increase in water production in

downdip wells or gas-oil ratios in updip wells may affectreserves booked in wells throughout the field. Prob-lems with unexpected changes in water or gas produc-tion typically result from uncertain drive mechanisms.

For example, consider the following: Undeveloped locations may have been bookedupdip of an existing location based on an expectedstrong water drive, but existing wells are experiencing

increased gas-oil ratios indicating a secondary gas capor a smaller-than-anticipated reservoir. Conversely, undeveloped reserves may have beenset up on strike with existing wells that water outprematurely because of expectations of a depletion orweak aquifer drive. Under such circumstances, notonly do the affected wells need to be re-evaluated butany undeveloped or behind-pipe reserves need to bereviewed as well.

Effect of depletion on behind-pipe and infill locationsEffect of depletion on behind-pipe and infill locationsEffect of depletion on behind-pipe and infill locationsEffect of depletion on behind-pipe and infill locationsEffect of depletion on behind-pipe and infill locationsEvaluators establish behind-pipe reserves and infill

wells at certain points in time under existing pressureand depletion (or sweep) conditions. Often, oil and gascompanies keep those reserves and wells “on thebooks” for several years or longer depending on theallocation of capital spending and timing of otherprojects.

Over time, the reserves engineer should re-evaluate volumes assigned to behind-pipe and infillwells as existing wells may have drained some oressentially all of these volumes, even in low-permeabil-ity reservoirs. A recommended approach to avoidcarrying reserves that may have already been drainedis to compare produced volumes with the expectedultimate recovery for the entire reservoir. Thisapproach allows timely adjustments to the remainingvolumes for behind-pipe or infill wells.

The reserves evaluator should reasonably expectthat the remaining volumes will be drained by theproposed behind-pipe completion or undevelopedlocations.

Other common problems with performance adjustmentsOther common problems with performance adjustmentsOther common problems with performance adjustmentsOther common problems with performance adjustmentsOther common problems with performance adjustments Recovery factors based on optimistic but uncon-firmed drive mechanisms Assumed well drainage areas or reservoir areas,such as updip locations or seismic amplitudes Setting up offset locations without compellingevidence of reservoir continuity

Events that should trigger review of all reservesEvents that should trigger review of all reservesEvents that should trigger review of all reservesEvents that should trigger review of all reservesEvents that should trigger review of all reserves New wells with unexpected changes in reservoirthickness, fluid contacts, pressures or productivity Early or unexpected water production or unantici-pated increases in gas-oil ratio Significant deviations from expected production orpressure-decline trends Reserves for undeveloped and behind-pipe locationsthat have not been reviewed in several years.

Guidelines to reduce frequency of mistakesGuidelines to reduce frequency of mistakesGuidelines to reduce frequency of mistakesGuidelines to reduce frequency of mistakesGuidelines to reduce frequency of mistakes Always review the potential field-wide implicationsof new data. Do not assume that, by chance, only poor locationsare drilled and good ones are yet to come. Exercise caution placing undeveloped locationswhere drive mechanisms or efficiencies are uncertain.

Editor’s Note: The Part 6 article in the March 2011Reservoir Solutions newsletter will conclude this seriesand focus on the impact of partial waterdrive andoverpressured reservoirs on gas material balance.Also examined will be undrilled fault blocks andeconomics projection programs.

Simulation—Cont. from Page 5

6 / March—May 2011Reservoir Solutions

Vol. 14, No. 1

Editor’s Note: This is a revised excerpt from “Oil andGas Reserves Estimates: Recurring Mistakes andErrors,” (SPE Paper No. 91069). To order a copy of thefull paper, go to www.onepetro.org and access the e-library.


This multipart article offers guidelines to helpreduce the chance of errors in geoscientific andengineering analysis. This sixth and concluding part inthe series focuses on the impact of partial waterdriveand overpressured reservoirs on gas material balance.Also examined will be undrilled fault blocks andeconomics projection programs.

Technical challenges in estimating reservesPart 6: Material balance, undrilled areas, economics

Effect of partial waterdrive and overpressuredreservoirs on gas material balance

The standard gas material balance analysis, p/zanalysis, is a common tool to determine both reservoirsize and recovery for a given abandonment pressure.Combined with volumetric estimates, gas materialbalance is an effective tool to estimate reserves,particularly in mature reservoirs.

Problems with gas material balance are typicallyencountered earlier in the field life when less than 25percent of the expected volume has been produced orwhen reservoir pressures are still above the normalpressure gradient.

During this early period, factors that influence thereservoir pressure behavior, such as compaction andpartial water drive, can be indistinguishable from apure depletion drive (Figure 16).

Although an evaluator sometimes faces difficultiesin isolating reservoir mechanisms that may affect thep/z trend, he can follow a few guidelines that willreduce the risk of overestimating gas in place andrecovery early in the field life.

Conditions that should trigger caution when usinggas material balance. Overpressured reservoirs with a gradient of 0.6 psi/ft or higher Small pressure change to original pressure, whichmay indicate water influx Apparent gas in place significantly larger than thevolumetric estimate Areas prone for water influx or high pressuregradients Cumulative production less than 25 percent ofexpected ultimate based on volumetric estimate High withdrawal rates that may mask water influxin early life

Guidelines to reduce risk of overestimating gas in placeGuidelines to reduce risk of overestimating gas in placeGuidelines to reduce risk of overestimating gas in placeGuidelines to reduce risk of overestimating gas in placeGuidelines to reduce risk of overestimating gas in placeand ultimate recovery using material balanceand ultimate recovery using material balanceand ultimate recovery using material balanceand ultimate recovery using material balanceand ultimate recovery using material balance Never base an early-life reserves estimate onmaterial balance alone. Include volumetric data andperformance analysis, if available. Review other, more mature fields in the area to

Figure 16. Conceptual gas material balance graph.

March—May 2011 / 7Reservoir Solutions

Vol. 14, No. 1

look for trends in p/z behavior and observed abandon-ment conditions. Overpressured reservoirs typically exhibit linear p/z trends until a normal pressure gradient is reached.Use caution and revert to volumetric analysis until asecond trend materializes below the normal pressuregradient. Be cautious in assuming low abandonment pres-sures if water loading becomes an issue. Include nodalanalysis calculations.

Assigning 1P reserves to undrilled fault blocksVirtually all recognized proved reserves definitions

refer to “known reservoirs” or “known accumulations”as a necessary qualifier to attribute proved reserves.Industry interprets the term “known” as that which isknown through a well penetration. Accordingly,evaluators do not classify undrilled fault blocks orreservoir segments as “proved” reservoirs. Seismicinterpretations may have advanced to the point wherea 90 percent confidence factor is attributed to anundrilled reservoir. However, this is not usuallyadequate enough to declare an undrilled fault block asa “known reservoir.”

Incomplete understanding of commercialeconomics projection software

R.S. ThompsonR.S. ThompsonR.S. ThompsonR.S. ThompsonR.S. Thompson and J.D. WrightJ.D. WrightJ.D. WrightJ.D. WrightJ.D. Wright in their 2001 paper,“A Comparative Analysis of 12 Economic SoftwarePrograms” (SPE 68588) investigated the use of eco-nomics software programs by their respective develop-ers. They developed 30 test cases with straightforwardassumptions about future oil and gas production rates,constant and variable gas-oil ratios and condensateyields and reversionary interests and overriding

royalties. Assumptions further included constant andescalated prices and costs. Results were to includefuture net income undiscounted and discounted atseveral annual rates.

These cases were not unusually complex or easilymisunderstood. The 12 vendors had one month tocomplete their forecasts. One of the simpler casesspecified a drilling cost, an initial monthly oil produc-tion rate, an effective annual decline rate, exponentialproduction decline, working and net revenue interests(constant), taxes as a percent of revenue and a begin-ning oil price and monthly operating cost, both esca-lated at 3 percent annually. The ranges in certainresults are tabulated below:

The expected case was prepared by the authorsand was essentially hand calculated over the five-yearproject life. The differences reported above arose fromone simple case but were magnified as example casesbecame more complex. How could this happen?

Different program assumptions were made involv-ing the number of days in a year, the timing of thereceipt of income, timing of expenses, differing dis-counting and escalation calculations and the timing ofpayouts triggering reversionary interests.

This study supports the notion that evaluators notrely on economics software unless they have developedhigh-level confidence through long-term use of theprogram and continuous review of the results.

Reservoir Solutions

Larry T. NelmsManaging Senior V.P.

Board of DirectorsBoard of DirectorsBoard of DirectorsBoard of DirectorsBoard of Directors

Don P. RoesleChairman and CEOJohn E. HodginPresidentFred P. RichouxExecutive V.P.

Ryder Scott Company LP1100 Louisiana, Suite 3800Houston, Texas 77002-5218Phone: 713-651-9191; Fax: 713-651-0849Denver, Colorado; Phone: 303-623-9147Calgary, AB, Canada; Phone: 403-262-2799E-mail: [email protected]

Editor: Mike WysattaBusiness Development Manager

Dean C. RietzManaging Senior V.P.Guale RamirezManaging Senior V.P.

George F. DamesManaging Senior V.P.

Jeffrey D. WilsonSenior V.P.

Herman G. AcuñaManaging Senior V.P.

CSA calls for caution when aggregating high estimatesThe Canadian Securities Adminis-

trators issued a staff notice Dec. 30 thatcalls for public issuers to use cautionarylanguage in their filings if they aggregatehigh-side resources estimates. “Disclosure of

the arithmetic sum of low or high estimates ofmultiple properties may be misleading,” saidthe CSA.

Mean or “best” estimates may be aggre-gated and disclosed without misleading readers of

financial information. However, statistical principlesindicate that the sum of multiple high estimates willlie beyond a reasonable range of expected actualoutcomes. The portfolio effect of aggregation alsoapplies to the addition of P10 reserves. If severalP10s at field levels are added together, the result is aprobability of much less than 10 percent.The cautionary language is as follows: This volumeis an arithmetic sum of multiple estimates of

[identify reserves or resource classes], whichstatistical principles indicate may be misleadingas to volumes that may actually be recovered.Readers should give attention to the estimates of

individual classes of [reserves or resources] and

appreciate the differing probabilitiesof recovery associated with eachclass as explained [indicate wheredisclosed and explained].

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