oklahoma: the ultimate oil...

“I saw it in the SHALE SHAKER” May-June 2008/ SHALE SHAKER 1

AbstractThe petroleum industry in Oklahoma

continues to be focused on natural gas,which today accounts for about 80% ofboth drilling activity and BOE production.Although there was a modest uptick in2006, the first since 1984, record pricesfor the last several years have had littleimpact on oil's long-term decline. Todaythe industry and the State are precarious-ly dependent on natural gas; the price ofwhich tends to reset each year based onthe severity of winter weather.

This study shows that an under-exploited opportunity exists in Oklahomathat is centered on improving oil recoveryin existing fields. The State's original oilin-place (OOIP) volume is over 84 BBO,and long-term decline projections showan estimated ultimate recovery (EUR) vol-ume of about 16 BBO. This 19% aggregaterecovery factor, which is the result of complex reservoirgeometries and poor reservoir management, equates to 68BBO being left in the ground at abandonment. If the stud-ies that were analyzed here are representative of the Stateas a whole, there are many opportunities, using simpletechniques, to economically recover additional oil in fieldsthroughout the State.

The major technical obstacle to a systematic search forthese opportunities is scattered, inaccessible, and incom-plete well and production data. This issue is now beingaddressed through an initiative, called Energy LibrariesOnline, of the Oklahoma City Geological Society and TheOklahoma Well Log Library, but this will require financialsupport to see it through. If operators are provided thetools necessary to identify this huge, untapped potential,a resurgence in oil activity and production is assured, withall of the financial benefits that these will bring to theindustry and the State.

Oklahoma Oil TrendsCurrent StatusOklahoma oil exploration began over 100 years ago,

with early successes propelling the territory to statehoodin 1907. Rapid development of many of the largest oilreservoirs led to State production peaking in 1927. Therehave been intermediate highs and lows in oil productionsince that time, with the last peak occurring during theprice-driven 'oil boom' in the late 1970s and early 1980s.Excepting a slight increase in the last year reported, oilproduction has declined steadily, regardless of oil price

since 1984. The disconnect between price and productionis demonstrated by the intermediate price peaks in 1990,1996, and 2000 that did little to slow the long-term dropin production, and the fact that it took four years ofrecord prices to achieve a modest bump in 2006 (Fig. 1).

The price of oil in Oklahoma, and the rest of the world,has been on an upward trend since 2002, with the 2006average price setting a record at $60.75/Bbl, and the 2007price sure to set an all-time record. Despite this, averagedaily oil production in 2005 dropped 8,165 BOPD; thelargest decrease seen since 1998. The production figuresshown in Figure 1 include condensate, but this representsless than 3% of the total liquid hydrocarbons produced(Claxton, 2007).

The easiest way to boost a region's oil production is tofind large, long-lived fields. Unfortunately, in Oklahomathose days are long past, as our last 100 MMB field (Postle)was discovered in 1958, and the last 10 MMB field(Wheatland) in 1981 (Boyd, 2002a). Over 500,000 wellshave been drilled in the last 100+ years, with tens of thou-sands of separate oil accumulations and over 3,000 namedoil fields discovered. As a result, although deeper poten-tial may exist in some older fields, the prospective oil-pro-ducing regions of the State have been extensivelyexplored.

Because discoveries are no longer a significant compo-nent of new oil production, future reserve additions mustlargely come from improvements to the recovery in exist-ing fields. Most Oklahoma oil production comes from fieldsthat have been producing for decades, and in which the

OKLAHOMA: THE ULTIMATE OIL OPPORTUNITYby Dan T. Boyd, Oklahoma Geological Survey

Figure 1: Oil production and average crude-oil price (unadjusted) in Oklahoma from 1950 through 2006.From Claxton (2007).

average well makes about 2 BOPD. Although small,undrained accumulations continue to be found, usually inor adjacent to existing fields, the possibility of finding oneor more new oil fields large enough to significantly affectthe State's long-term production decline has become van-ishingly small.

In 2006 over 4600 wells were completed in Oklahoma,with 22% of these (1043) as oil completions. Most of thesewere in existing fields, with more than one quarter of thetotal being workovers (IHS Energy, 2008). Oil-targeteddrilling has grown since the price run-up that began in2002, but the increase in oil completions is less than athird that of gas. In fact, oil drilling activity is still insuf-ficient to maintain well numbers (Fig. 2). In the last fiveyears pluggings have outstripped new oil completions bytwo to one, reducing the number of active wells by 1,600to a total of about 80,000 (Claxton, 2007).

There are plausible explanations for why oil drillingand production continues to fall in a high price environ-ment: 1) Operators are concerned that current prices willnot hold long enough to recoup large initial investments,2) The economics for natural gas are better, giving gas-tar-geted drilling an advantage, or 3) There is not enough pro-ducible oil left to justify a large-scale evaluation ofimproved recovery projects.

1) Long-term price forecasts can be driven by manyfactors that are impossible to predict, and operators inOklahoma have been affected by all of them. Although itis easy to understand a hesitancy to invest in oil, it isbelieved that over the long term demand will continue torise and oil prices will remain strong (Boyd, 2005).Regardless of one's view of when or if 'peak oil' will occur,in today's world there are certainly many more factors thatcould bring about price increases than those that couldpush prices lower.

2) Because of the concurrent rise in natural gas pricesthere is no question that the average gas well inOklahoma, which produces about 135 MCFPD, can nowgenerate more cash flow than the average oil well. Usingthe standard energy conversion of 6 MCF per barrel thisequates to 22.5 BOEPD, or about 10 times what the aver-age oil well produces (2.1 BOPD). Using average 2006prices this means that, in terms of gross revenue, the aver-age gas well can make about $848 per day, while an oilwell only about $128 per day. Although gas wells are moreexpensive to produce and maintain, the income discrepan-cy is huge, making industry's preoccupation with gas easyto explain.

3) Is there enough producible oil left for it to make acomeback? This cannot be easily answered, because eacharea, field and reservoir must be evaluated on its own mer-its. This review will show that there are many fields thathave seriously underperformed when compared to closelyanalogous fields. However, the objective here is not toevaluate the economics of individual oil projects, but sim-ply to prove that sufficient potential exists to justify eval-uating the possibilities.

History (How We Got Here)Oil exploration in Oklahoma began before there was

any real understanding of why and where it might occur.It had been known to exist in the subsurface long beforeStatehood through the drilling of water wells that becamecontaminated by crude oil. Early wells intentionally look-ing for oil were usually drilled near seeps, with the firstcommercial success coming adjacent to a seep nearBartlesville in 1897. The Nellie Johnstone ushered in theoil age to Oklahoma and began a meteoric rise in territo-rial and then State fortunes in which annual crude pro-duction went from 1,000 barrels in 1897 to 43.5 million

barrels in 1907 - the year of Statehood(Franks, 1980) (Fig. 3).

The oil produced in 1907 was only thebeginning, as the oil-rush continued witha steady stream of enormous discoveries.These included Cushing (1912), Burbank(1920), Seminole District (1923), andOklahoma City (1928), each of whichwould produce more than 500 MMBO (Fig.4). Oil production peaked in 1927, androse and fell many times thereafter.Increases in production came through dis-coveries, increased allowables, large sec-ondary recovery projects, or price-drivensurges in drilling activity. Falls in produc-tion were caused by forced curtailment(due to low price), reduced drilling activ-ity, or, as is the case now, a natural, long-term decline in field production.

All geologic provinces eventuallyFigure 2: Oklahoma well-completions from 1980 through 2006, showing the trend away from exploration,based on dry hole percentage, and towards gas development. From IHS Energy, 2008.

206 SHALE SHAKER /May-June 2008 “I saw it in the SHALE SHAKER”

“I saw it in the SHALE SHAKER” May-June 2008/ SHALE SHAKER 3

reach a point at which the potential reward no longer jus-tifies the risk and expense of large-scale exploration.When that occurs activity moves elsewhere, and forOklahoma this happened in the late 1960s. The price ofcrude oil had remained nearly flat for decades, and dis-covery sizes no longer justified widespread exploration. In1967 oil production began a long downhill slide that wasonly briefly interrupted by the drilling boom in the late1970s and early 1980s (Fig. 1).

Most of the oil discovered in Oklahoma was found dur-ing a time when natural gas, especially that seen in asso-ciation with oil, was viewed mainly as a drilling hazard.Early wells were drilled with cable tool rigs that, unlikemodern rotary rigs, operate without drilling mud andtherefore any mechanism to control fluid flows. A discov-ery meant a blowout, with gas in the air and oil on theground. The gas was vented or flared and earthen damswere used to collect the oil. If a well encountered a largegas flow, it would be vented, sometimes for days, to deter-mine if there was an oil rim beneath. If oil did eventuallycone into the well, the oil was produced and the gasflared. If not, the well would be plugged. An example isthe discovery well for Wewoka Field, the R. H. Smith - #1Betty Foster, which was drilled in March 1923. After pen-etrating a few inches into sandstone, this well blew outflowing 20 MMCFPD and 'spraying oil'. The 'oil', whichclearly was initially gas condensate, increased to 200 BOPDin a few days as underlying oil coned into the well, caus-

Figure 4: Map of major geologic provinces of Oklahoma showing oil and gas fields distinguished by GOR and oil fields with more than 500 MMB recovery. Modified fromBoyd (2002b).

Figure 3: The Nellie Johnstone #1, drilled in 1897 just south of Bartlesville,established the first economic production in Oklahoma. Photograph taken fromFranks, 1980.

4 SHALE SHAKER /May-June 2008 “I saw it in the SHALE SHAKER”

ing the gas flow to decrease. This permitted a deepeningof the well, making it capable of a rate of 3,500 BOPD(Franks, 1980).

The frontier mentality in the State's early historymade it reluctant to intervene in what were viewed as 'pri-vate business practices'. Although the OklahomaCorporation Commission was formed in 1907 to regulatethe oil industry, the organization was chronically under-staffed. The lack of inspectors forced it to rely on an honorsystem in which the industry became largely self-regulat-ing. As a result, independent oil producers themselveswere the first to address what were termed 'intolerableconditions in the oil fields'. In addition to numerous largeoil spills and fires, these conditions included a waste ofnatural gas that by 1913 had assumed 'scandalous propor-tions'. In this year the federal government estimated that$20,000 of gas was wasted each day at Cushing Field alone,and that the daily waste of gas Statewide was equal to10,000 tons of coal. (Using the standard of 14 cf per poundof bituminous coal, this equates to 280 MMCFGPD or 102BCF in that year.) This attention was viewed by many as apretext for the federal government to extend its authorityover Oklahoma. This never happened, but it did promptpreventative action to be taken. In 1914 the OIPA advo-cated regulation of the industry, with the focus on prora-tioning. (Franks, 1980).

The practice of flaring huge quantities of gas inOklahoma's early oil fields, with the resulting loss of reser-voir energy, had a devastating impact on recoveries andcaused rates to plummet after peak production wasreached. Healdton Field, which was discovered in 1913,peaked in 1916 at 95,000 BOPD. (It was noted in Franks,1980 that individual wells in this field were flaring up to13.5 MMCFGPD.) By 1918 the field was capable of only

40,000 BOPD, and by 1924 only 16,000 BOPD. Anotherexample is Burbank Field, where July 1923 peak produc-tion of 122,000 BOPD fell to an average in 1924 of 60,000BOPD, which further fell to 37,000 BOPD by 1926.Although the presence of abundant gas in the oil had thebenefit of making pumping equipment unnecessary, flar-ing was recognized, even at this time, as reducing oilrecovery. However, the atmosphere was such that large-scale gas flaring remained the accepted practice (Franks,1980).

The volume of gas flared in the early days in Oklahomais impossible to quantify directly because flow rates wereguesstimates and there was no requirement to report gasproduction that was not sold. In the studies reviewed forthis report it was found that most oil accumulations werefound at or just below gas saturation. This is confirmed bythe number of fields that were discovered with small gascaps or formed secondary gas caps immediately after pro-duction began. The average (weighted by field size) initialgas to oil ratio (iGOR) for the fields studied was 665 stan-dard cubic feet per stock tank barrel (scf/STB). This is insubstantial agreement with the average (unweighted)iGOR from the government compiled in the TORIS data-base, which is 724 scf/STB (U. S. Dept. of Energy, 1984).

If the average produced GOR through abandonmentpressure is roughly three times the initial value (Knapp,2006), the Statewide associated gas volume should beabout 1995 scf/STB. By linking gas with oil production inthis way it becomes possible to estimate how much asso-ciated gas was liberated as oil was produced. By subtract-ing from the associated gas volume the gas that was actu-ally sold, it is possible to estimate how much was ventedor flared. This estimate ignores non-associated gas thatmay have been flared from gas caps. It also assumes that

all gas sold was associated gas which,given high GORs and huge oil sales, seemsa safe assumption (Fig. 5).

The first year in which more than 1BCF of gas was officially sold in Oklahomawas 1906. From this time, peaking in 1927and continuing through 1942, the calcu-lated volume of associated gas is muchgreater than that on which taxes werepaid. From 1900 through 1942, 6.9 trillioncubic feet (TCF) of gas and 5.13 BBO weresold. The oil produced should have gener-ated 10.2 TCF of associated gas, so if theproduced GOR estimate is accurate, thevolume of gas vented and flared inOklahoma during this time was about 3.3TCF. This formula generates a 1913 flaredvolume of only 53 BCF, which is roughlyhalf the previously quoted federal esti-mate of 102 BCF for that year. Although 3to 6 TCF is a relatively small amount in a

Figure 5: Estimate of associated gas production in Oklahoma from 1900 through 1942. Production basedon an average produced GOR of 1995 scf/Bbl. Flared/vented gas is the difference between the total calcu-lated and that sold.

“I saw it in the SHALE SHAKER” May-June 2008 / SHALE SHAKER 5

State that has already sold more than 97 TCF, its realimpact was in the reduction of oil recoveries.

There were other early practices that reduced oilrecovery, including 1) the coning of water into oil reser-voirs through over-production, 2) uncoordinated, patch-work waterfloods in which a poorly understood reservoirgeometry left large areas unswept, and 3) subsurfacecross-flow in which commingled zones exchanged fluids orwhere uncased wells allowed oil reservoirs to charge per-meable water-bearing zones. However, the practice thathad the most profound impact on oil recovery in the Statewas that of gas flaring. This reduced recovery by rapidlyreducing reservoir pressure and gas saturation in the oil,and by leaving behind unproducible oil saturationsthrough the smearing of oil into gas caps. Ultimately how-ever, this is water under the bridge. What is important isthat a great deal of oil remains in the ground.

The Future (Where We're Going)One of the objectives in this analysis was determining

how much oil will be left in the ground, given a continu-ation of the current production decline. The first step inthis process is a determination of ultimate recovery. Thistask is never easy, but it is made simpler by the fact thatmost of the State's production comes from wells that haveproduced for decades, and because discoveries largeenough to affect State production will no longer occur.

In the latest reserve estimate in 2005, which is basedon a poll of the State's operators, the Energy InformationAdministration of the U.S. Department of Energy project-ed Oklahoma's proved oil reserves at 588 MMBO (E.I.A.,2005). The same poll taken in 2000 placed reserves at 621MMBO, meaning that proved reserves dropped only 33MMBO in a five-year period in which 332 MMBO were pro-duced. Obviously, the near doubling ofcrude oil prices in that period did much toimprove the average operator's outlook,but through it all the decline in produc-tion since 1995 has averaged about 3.5%per year.

If State production remains in long-term decline, notwithstanding the uptickin 2006, it is possible to calculate a rangeof remaining oil reserves. Although thisestimate carries many assumptions, itdoes show the effect that changes in thelong-term decline have on EUR volumes.Using the 3.5% decline experienced since1995, and carrying it through the year2050, remaining reserves as of January2007 were 1,371 MMB. If the decline isincreased to 4.5%, or about the 2005decline, remaining reserves through theyear 2050 are 1,158 MMB (Figure 6). If theaverage net loss of about 300 oil wells per

year holds (Claxton, 2007), in 2050 there will be about66,000 producing wells, making the per-well ending ratein these cases about 1/2 BOPD and 1/3 BOPD. The cutoffin 2050 and the resulting per well production rates werearbitrary, as the actual economic threshold is impossible topredict.

Given these assumptions, the range of remaining oilreserves is surprisingly narrow. In both the 3.5% and 4.5%decline cases, remaining reserves are significantly greaterthan the 588 MMB reported by the E.I.A. So, given a con-tinuation of current trends in drilling and plugging, andan average abandonment rate for an oil well in Oklahomaof less than ½ barrel per day, there is good reason tobelieve that more than a billion barrels are left to produce.This means that in a status quo situation, ultimate recov-ery for the State will be slightly more than 16 BBO. Thegood news is that, short of a price collapse, the chancesare excellent Oklahoma will produce at least twice the oilnow carried as reserves. The bad news is, if correct, we areabout 92% produced and the end is in sight.

Defining Oklahoma's Oil ResourceProcedureThis is clearly a daunting task, but a determination of

the remaining oil in-place first requires an estimate of thevolume that was originally in-place. The State containstens of thousands of separate oil accumulations, at depthsfrom a few hundred to more than 11,000 feet, located inthousands of fields scattered across almost every county.This oil resides in hundreds of named reservoir-intervals ofevery description, trapped in every conceivable trap type(structural, stratigraphic and combination), and has beenproduced through a variety of natural and artificial drivemechanisms. Given such complexity, the key is simplifica-

Figure 6: Projected Oklahoma oil production using 3.5 and 4.5% annual declines through 2050. Both casesend with the average well producing less than ½ BOPD. This suggests the ultimate oil recovery for the Statewill be slightly more than 16 BBO.

6 SHALE SHAKER / May-June 2008 “I saw it in the SHALE SHAKER”

tion. This begins with the placement of all oil reservoirsinto three major classes: Blanket Sandstones (BS),Carbonate Shelves (CS), and Fluvial-Dominated DeltaicSandstones (FDD). These correspond to what theDepartment of Energy calls Strandplain\Barrier, ShallowShelf\Open, and Delta\Fluvial Dominated reservoirs (U. S.D.O.E., 1993).

To draw statistically meaningful conclusions, reservoir,fluid, and related data were gathered on as many oil accu-mulations as possible. Because of the time necessary toproduce these data from scratch, and because so muchexcellent work has already been done, information wasacquired primarily through studies available in the litera-ture. Although those with volumetrics were the most use-ful, valuable data were gleaned from work from even inthe earliest days of the industry, where oil/gas analyses,initial rate and GOR, cumulative production by reservoir,and production techniques were noted. The best reservoirdescriptions, including core-derived porosity/permeabili-ty, begin in studies from the late 1940s, with volumetricanalyses becoming routine by the mid-1950s. The qualityof the work in these studies was generally quite good, andeven those with missing data or ambiguous results con-tributed valuable information.

The data recorded include general location informa-tion, reservoir property and trap information, fluid prop-erties, production and volumetric calculations, and infor-mation concerning the study type and issues affecting itsapplicability. The studies originated from a variety ofsources, including 1) the Oklahoma Geological Survey, 2)publications from the AAPG, the Journal of PetroleumTechnology, and the Oil and Gas Journal, 3) professional

groups, including the Oklahoma City, Tulsa, Ardmore, andPanhandle Geological Societies, 4) governmental studiesfrom the US Bureau of Mines, the USGS, the Department ofEnergy, and the Oklahoma Academy of Science, and final-ly 5) theses and dissertations from OU. Where possible,these data were compared to that published in the TORISdatabase (U. S. Dept. of Energy, 1984).

Each of the 225 studies examined had useful informa-tion, but the volumetrics and recovery factors in manywere unusable. For these the most common disqualifierwas the inability to confirm production, either because ofmissing data, or because the productive area had increasedto the point that the study's volumetrics had becomemeaningless. Many excellent field studies had to beexcluded from recovery factor statistics because cumula-tive production quoted from original operator records,often from the 1950s or 60s, was much more than thatshown in the latest IHS data. For fields in which produc-tion was shown as commingled, production was onlyassigned to leases in which the reservoir under study waslisted first. Of the studies with volumetrics that werereviewed, roughly half (123) had verifiable production(BS-24, CS-25, FDD-74) (Fig. 7). (Appendix). Recovery fac-tors are based on these studies.

The three reservoir types, although very broad, areuseful in defining some of the most fundamental factorsaffecting oil recovery. These include subsurface geometry,reservoir heterogeneity, pore volume, porosity type(s) andpermeability. The impact these factors have on fluid move-ment through the reservoir helps determine drive mecha-nism, and ultimately recovery factor. By comparing oilfields with similar trap types and reservoirs it becomes

Figure 7: Map showing major geologic provinces and the location and reservoir class of the reservoir studies that were analyzed in this report.


possible to assign an 'ideal' recovery factor to similar fieldsbased on the results of those that performed the best. Ina review of this nature, it is impossible take into accountall of the variables that can affect recovery factor.However, general rules of thumb can be drawn for commonreservoir/trap types that can help identify under-perform-ing fields throughout the State.

Blanket Sandstones (BS) refer primarily to theOrdovician-age Simpson reservoirs, which are clean, well-sorted, high quality sandstones. These include theBromide, McLish, Oil Creek, Tulip Creek and WilcoxSandstones (Fig. 8). A single Misener study was includedin this group because, although aerially restricted, it iscomposed of eroded Simpson-age sandstones, with similarporosity and permeability (Appendix). Blanket sandstonereservoirs generally have high porosity and excellent per-meability. They are laterally continuous, and as a result,trap only on structural highs. Their drive mechanism isdominantly solution gas drive, with varying degrees ofwater support. Water movement is dependent on howmuch reservoir below the oil/water contact is in commu-nication with the oil trap, which in these laterally contin-uous reservoirs is usually controlled by faulting off-struc-ture.

Carbonate Shelf (CS) reservoirs studied are limestonesand dolomites ranging in age from the Cambro-OrdovicianArbuckle dolomite to the Mid-Pennsylvanian OswegoLimestone. The most important producersin this category are the Arbuckle, Huntonand various Mississippian limestones.Carbonate reservoirs are often strati-graphically trapped along the regionaltruncation of a porous facies, but whereporosity is pervasive they can also befound structurally trapped. Carbonatesare often dual-porosity reservoirs inwhich a low porosity/permeability matrixis enhanced by dissolution features(molds, vugs, and caverns) and fractures.The dissolution features and fracturesgreatly increase wellbore access to thelower permeability matrix that would oth-erwise not be of reservoir quality. A singleArkansas Novaculite study was included inthis group because of its similar dual-porosity system and production character-istics (Appendix).

Fluvial-Dominated Deltaic (FDD)reservoirs are by far the most importantgroup in Oklahoma. They arePennsylvanian and Permian in age, withthe most productive being theBartlesville, Deese, Morrow, and Red Fork.They are a diverse group of sandstones,which although mostly deposited as

channel-fills (distributary channels and incised valley-fills) also include overbank splays and various types ofmarine-reworked deltaic sandstones, including distribu-tary mouth bars and tidal channels. Reservoir quality ishighly variable, with the various channel-fill sandstonesbeing by far the best. The defining characteristic of FDDreservoirs is their limited aerial extent and a complex sub-surface plumbing system. For this reason, although struc-ture can sometimes influence the trap, even FDD reservoirsoccurring on structural highs have a strong stratigraphiccomponent. Like the BS reservoirs, the drive mechanismtends to be solution gas drive, but with little or no watersupport (Fig. 8).

The published findings were generally taken at facevalue, under the assumption that in a large sample thereshould be an equal tendency to overestimate as underesti-mate any particular parameter affecting volumetric calcu-lations. There were several cases in which all of the keyvariables necessary to estimate OOIP were provided, butthe calculated recovery factor turned out inordinatelyhigh. For some the calculated recovery factor was multi-ples of the reservoir class average, such as an FDD reser-voir with more than a 70% recovery factor. Anomaliescould usually be traced to the addition of zones within thereservoir interval, or an expansion of the productive areasince the study date. Reservoir and other data from thesestudies were still valid, but these fields were omitted from

Figure 8: Generalized Oklahoma stratigraphic column highlighting the oil reservoir classes and the names ofthose reviewed in this report.


recovery factor statistics. Although disqualifying studiesin which the recovery factor was deemed too high mayintroduce a systematic error that would tend to underesti-mate recovery factors, smaller scale commingling in thosestudies that were used should tend to cancel this poten-tial bias.

This analysis is predicated on a number of keyassumptions. The first is that the fields and reservoir stud-ies that were reviewed represent a statistically representa-tive cross-section of those that exist throughout theState. Also, because the work of dozens of geologists hasbeen used, one must assume that the studies are of equalquality and that there is no systematic bias that wouldtend to over- or underestimate recovery factors. As willnow be discussed, the largest source of uncertainty in thisanalysis is not in the pore volumes calculated, but in theoil produced.

ChallengesThere were many challenges associated with a project

of this scope, but by far the most serious involves dataavailability, especially early production data. The bestpublicly available database in Oklahoma is that compiledand maintained by IHS Energy. Their monthly oil produc-tion data begins in 1970 and their well database hasrecords for about 485,000 wells. The State database(NRIS), which is offered online by Oil Law Records, beginsmonthly oil production in 1979 and has records for about450,000 wells. The total number of wells drilled inOklahoma is believed to be well over 500,000. Because ofits earlier start date for monthly production and largernumber of well records, the IHS Energy database was usedto confirm and update production for the studies thatwere reviewed.

Unfortunately, even the IHS Energy database has someserious shortcomings, most of these due to circumstancesbeyond their control. Because the State has not consis-tently distinguished condensate from oil, all volumesquoted as oil refer to total hydrocarbon liquids. If theaverage condensate yield for all Oklahoma gas reservoirs is5 barrels per MMCF, this would amount to roughly 500MMBC lumped into the gross oil production volumes. Whilethis is a large volume, it still represents only about 3% ofthe total liquid hydrocarbon production for the State.

There are other, more serious production data issues.Using Tax Commission data, the Oklahoma CorporationCommission has compiled annual, statewide 'oil' produc-tion volumes since 1900 and annual volumes by countysince 1975. These official numbers show a cumulativerecovery of 14.809 billion barrels (Claxton, 2007). Totalproduction in the IHS Energy database, including the'beginning cums' which refer to production prior to 1970,is 12.873 BBO (IHS Energy, 2008). The missing 1,936MMBO, representing 13% of State production, is notaccounted for in any digital database. Fortunately, a ran-

dom comparison of IHS to Vance Rowe (hard copy) pro-duction in fields that appeared to be underreported con-firms that much of the 'missing' oil is carried by VanceRowe.

An additional 2,995 MMBO, or 20% of State produc-tion, was produced from wells in which the cell for pro-ductive reservoir is either blank or marked 'Unknown'. IHSEnergy records multiple reservoirs for wells in which morethan one reservoir was listed by the operator, which hashelped identify the source for some commingled produc-tion. However, for 383 MMB of production, or 3% of Stateproduction, the official reservoir name is 'Commingled'.

Another production data problem relates to oil pro-duced from secondary/enhanced recovery units, usuallywaterflood units. Here the State has no requirementsregarding water injection or production, only requiringoperators to report the total monthly (oil-gas) volume forthe entire unit, regardless of its size. With operatorrecords now largely lost, it has made it all but impossibleto identify areas in larger waterflood units where pro-ducible volumes of unswept oil may still reside. This poli-cy has resulted in a single quarter-quarter section inCushing Field assigned a cumulative production of 425MMBO, and one at Burbank with 315 MMBO (IHS Energy,2008).

Thus, in the most complete production database in theState, a total of 5,314 MMB, or 36% of total production, iseither missing or has no reservoir identified. This hasmade it nearly impossible to determine cumulative recov-eries or calculate recovery factors for fields that were thesubject of excellent studies. Often cumulative productionshown through the date of the study, usually in the 1950sor 1960s, and provided by the operator, is many times thatshown by IHS as the cumulative production through 2008.Such studies could not be used in recovery factor statis-tics.

ResultsWith a 16 BBO estimate of ultimate oil recovery, the

next step is to determine the OOIP volume from which thisproduction has or will come. Because recovery factors varywith reservoir type, this involves apportioning cumulativeproduction into one of the three reservoir classesdescribed previously. This fixes the relative contribution ofeach class, which combined with an average recovery fac-tor based on field study statistics, makes it possible to cal-culate an overall OOIP.

Classifying each Oklahoma oil reservoir into one ofthree reservoir classes at first seems daunting. The N.R.I.S.listing of productive reservoirs includes about 7,500names, exactly as reported (and spelled) by operators.Even IHS Energy, which has streamlined this list, still hasover 3,000 named reservoirs. Luckily, the vast majority ofoil reservoirs have less than a handful of completions, andwith this in mind, only those reservoirs with at least 10


completions were counted. Commingled completions,where the individual reservoirs were identified, had theirproduction assigned to the first reservoir listed.

There are only 167 reservoirs with at least 10 oil com-pletions, and although they represent a small percentageof the total named, they account for over 98% of the 9,280MMBO assigned to specific reservoirs (IHS Energy, 2008).There are 6 BS, 36 CS, and 125 FDD reservoirs with at least10 oil completions. By summing their production it wasfound that BS reservoirs accounted for 17.5%, CS reser-voirs 18.5%, and FDD sandstones 64.0% of the State'scumulative production that is assigned to a specific reser-voir (Figure 9).

If it is assumed that unassigned and missing produc-tion is of a roughly equal proportion, the actual cumula-tive production for the three reservoirclasses to date is: 2,592 MMBO for BSreservoirs, 2,740 MMBO for CS reservoirs,and 9,478 MMBO for FDD reservoirs. If thewells producing from these reservoirsdecline at roughly the same rate, theyshould also make up the same proportionof the ultimate oil recovery. Thus, givencurrent trends, roughly one sixth ofOklahoma's ultimate oil recovery willcome from BS reservoirs, one sixth fromCS reservoirs, and two thirds from FDDreservoirs. This may actually understatethe relative importance of FDD reservoirsto Oklahoma, as much of the unassignedproduction, which was produced mostly inthe early years, was from the shallowerFDD reservoirs.

In addition to collecting data on all ofthe variables affecting volumetric calcula-

tions, a great deal of other informationwas also gathered. In this way, studiesthat had incomplete or unverifiable infor-mation concerning volumetrics couldmake valuable contributions in otherareas. The following is a brief summary ofsome of the geological/engineering find-ings that were gathered from the 225 oilfield studies that contributed in some wayto this report.

In the studies reviewed reservoirdepths ranged from 720' to 11,400', withthe vast majority between 3,000 and9,000'. For those giving an initial reser-voir pressure, it was found that two thirdsbegan at or near hydrostatic (0.43psi/ft.), or 'normal' pressure. The remain-ing third were mostly underpressured,with most of these located on theAnadarko Shelf. The few that began over-

pressured were mostly in the Anadarko Basin. It was rarelyindicated whether the initial reservoir pressure was meas-ured directly or calculated from the shut-in tubing pres-sure. Those that were calculated will tend to underesti-mate the true bottom-hole pressure, and this may accountfor some reservoirs that appear to have started underpres-sured.

In fluid properties, as stated earlier, the weightedaverage for the IGOR was 665 scf/Bbl. The distribution ofoil gravity ranges from a low of 20° API to a high of 50°API, with most values between 37° and 42° API (Fig. 10).Taking the published numbers at face value, the averagegravity for the oil in the studies reviewed was 39.6° API.However, any values in the mid-40s and higher are likelyin part condensate, which if discounted, would reduce the

Figure 9: Oklahoma oil production by reservoir class.

Figure 10: API gravity range for the studies analyzed in this report. The higher values probably have a com-ponent of gas condensate.


overall average. Regardless of any possible inconsistencies,the bulk of the crude oil found in Oklahoma is high-qual-ity, very light, and began with ample dissolved gas.

Reservoir statistics, which were only core-derived,quantitatively highlight some of the differences betweenthe three reservoir classes. Although they were depositedin different environments, BS sandstones and FDD sand-stones have similar porosity distributions. The FDD reser-voirs are more numerous, but the average porosity in theiroil pay, at 16.2%, is very close to the blanket sandstone's15.2%. The porosity distribution (matrix) for CS reservoirs,as well as their average porosity of 7.9%, is much lowerthan that of the other two reservoir classes. In fact, with-out the dissolution/fracture component, many of these

would not be of reservoir quality (Fig.11).

Core permeability values were record-ed in many of the studies that werereviewed, and here the two sandstonereservoir classes differ. The FDD reservoirswere deposited mostly as channel-fillsand therefore contain more fine-grainedmaterial than the well-winnowed blanketsandstones. Although the FDD sandstonescan be as permeable as the BS, their aver-age permeability is 68 md, compared tothe BS sandstone's 121 md. The CS reser-voir's distribution is somewhat bimodal,with all but three reservoirs having verylow permeability. The 21 md average ismisleading because it applies to only whatcan be effectively measured from core i.e.:matrix permeability. In the subsurfacethis lower matrix permeability can begreatly improved by dissolution featuresand especially fractures; both natural andartificial (Fig. 12).

Oil in the GroundRecovery factor ranges were calculat-

ed for each of the three reservoir classes.These are based on the studies in whichthe OOIP was given or where enough crit-ical information was given to calculatethe OOIP. In those cases where the initialoil saturation or formation volume factorwas not given, these values were estimat-ed based on comparisons to analog fields.(OOIP = Area in acres x Thickness in feet xAverage Porosity % x Average Initial OilSaturation % x 7,758 Barrels per Acre-Foot/ Formation Volume Factor in ReservoirBarrels per Stock Tank Barrel).

For each of the studies reviewed theEstimated Ultimate Recovery (EUR) was

calculated by maintaining the last month's production flatfor 8 years and adding this to cumulative production (Fig.13). This simplistic approach, because of almost universal-ly low production rates, seldom left more than a few per-cent of the EUR left to produce. However, if oil prices cankeep wells economic and producing significantly below1/2 BOPD, this estimate will be somewhat conservative.Because EUR is a fraction of OOIP, an error of a few per-cent in the EUR will have a minimal impact on the overallrecovery factor.

The recovery factors that were calculated for fields ineach of the three reservoir classes varied considerably, insome cases due to the nature of the reservoir, in othersbecause of how it was produced. Carbonate shelf reservoirs

Figure 11: Average porosity by reservoir class. Values are averages of the productive part of the reservoirfor the studies analyzed in this report.

Figure 12: Average permeability by reservoir class. Values are averages of the productive part of the reser-voir for the studies analyzed in this report.


tend to concentrate on the lower end of the recovery scale,while the blanket sandstones stand out in the higherranges. Average recovery factor values for each reservoirclass were weighted by dividing the summed EURs by thesummed OOIPs. This gives larger fields, which account forthe bulk of production, more weight thanthe more numerous small fields. Thisweighting should give a more representa-tive picture of the average recovery factorfor the three reservoir classes. The higherlevel of attention focused on larger fieldscould also give them better recovery fac-tors than similar reservoirs in smallerfields. The following are the average ulti-mate recovery factors calculated forOklahoma's major reservoir classes:Blanket Sandstone - 44.1%, CarbonateShelf - 10.0%, and Fluvial-DominatedDeltaic Sandstone - 21.2% (Fig. 14).

Assuming that recovery factors fromthe oil reservoirs in this study are repre-sentative of those throughout the State,it becomes possible to calculate an OOIPfor all of Oklahoma. Based on the propor-tionate share of total production of thethree reservoir classes stated above, theaggregate recovery factor for all oil reser-voirs in the State is about 19.0%. Thisyields an OOIP for the State of 84.2 BBO,with 68.2 BBO projected to still be in theground at abandonment. This assumes acontinuation of the current productiondecline until an ultimate recovery of 16.0BBO (an additional 1.2 BBO) is reached.Clearly, any program that can yield even asmall percentage of the oil left behind hasthe potential to dramatically increase theState's EUR (Fig. 15).

Because every oil accumulation is dif-ferent, even in the same reservoir class, awide range of recovery factors are possi-ble. In BS reservoirs with high permeabil-ity, if the structure is unbroken and watersupport strong, recovery factors well over50% are possible. Despite this, about half

of the studies reviewed calculated recovery factors of lessthan 30%, often substantially less. In some cases thisreflected poorer reservoir quality, but more often occurredin structurally complex fields. Unlike unbroken structuresthat are essentially self-flooding, these tended to have

Figure 13: Size range, in MMBO of cumulative recovery, for fields in which recovery factor was calculated.

Figure 14: Recovery factor by reservoir class for fields in which recovery factor was calculated.

Figure 15: Table showing Oklahoma original and remaining oil in-place volumes (MMBO) by reservoir class. Share of cumulative production based on proportions of IHSEnergy production assigned to specific reservoirs. OOIP volumes assume same recovery factor for all production from that reservoir class and are based on an EUR of 16BBO.


weaker water support and a higher probability ofundrained fault-blocks or missed attic oil.

In the CS reservoirs, where matrix porosity and per-meability are relatively high and secondary porosity in theform of vugs and fractures are abundant, recovery factorsof over 35% were recorded after waterflooding. However,about half of the studies reviewed had recovery factors ofless than 15%. For many of these the oil producedappeared to have come mostly from the secondary porosi-ty system, with little input from the poorer qualitymatrix. For those fractured carbonate shelf reservoirs withpoor quality matrix, production usually started verystrong, but declined dramatically within a few months. Ade-watering program designed to reduce reservoir pressureand force matrix oil into the fracture system may be ableto substantially improve recovery in some of these.

The largest reservoir class in Oklahoma is the FDDsandstones. They account for about two thirds of the OOIP,and have recovery factors that range from 52% to less than5%. Stratigraphically they are by far the most diverse classof reservoirs, ranging from multi-story channel-fills morethan 200' thick with 25% porosity and darcies of perme-ability, to overbank splay or mouth bar sandstones a fewfeet thick that can barely flow oil. The majority of thosestudied in the literature were the better quality FDD reser-voirs, i.e.: channel-fill sandstones, where the better recov-eries after waterflooding range from 32% to 44%. For mostof the FDD channel-fill oil reservoirs a typical scenarioinvolves primary production of 10 to 15% of the OOIP, fol-lowed by secondary (waterflood) recovery of an additional10 to 15%. In cases where flow barriers are minimal andsweep efficiency is good, even higher recoveries are possi-ble. For the roughly half of FDD channel-fill reservoirs inwhich the estimated recovery factor is less than 20%, amore detailed review is certainly warranted.

In spite of the rather arbitrary cutoffs quoted, areview of oil reservoirs for improved recovery should notbe restricted to those below a particular recovery factor.Rather, on a first pass screening, BS reservoirs with lessthan 30%, CS reservoirs with less than 15%, and FDD reser-voirs with less than 20% are obvious candidates for a clos-er look. Few of the studies reviewed quoted irreducible oilsaturations or movable oil volumes. However, with thethree reservoir classes leaving behind 56% to 90% of theOOIP, in most cases the critical issue should not be the vol-ume of movable oil.

There are many ways in which the results cited herecould be somewhat inaccurate. However, because of theoverall quality of the studies on which the statistics inthis report is based, there is little doubt that if trends con-tinue, a very large volume of producible oil will be left inthe ground at abandonment. A number of these studieswere able to accurately predict ultimate recovery (primary+ secondary) only a few years after the discovery of afield. Some, often with the help of a reservoir simulation,made recommendations concerning how to improve recov-ery, including changes in the injection pattern, re-com-pletions, or new wells that, despite large incrementalrecovery estimates, were never implemented. Some fieldswere waterflooded, while others that appeared analogous,were not. In others the flood response was weak ordelayed, indicating poor sweep. For many, the field thatwas studied significantly under-performed relative toanalogous reservoirs under similar conditions.

If the studies evaluated here are even remotely repre-sentative of the State as a whole, the possibilities forimproving oil recovery seem nearly endless. Although eco-nomics were not considered, a large percentage of thefields reviewed, in all three reservoir classes, appeared tohave significant improvement potential. High quality seis-mic is an important component in evaluating most BS orstructurally trapped CS reservoirs. Overall, the best possi-bilities are in the FDD reservoirs, which represent thelargest volume of remaining oil, and where complexstratigraphy has created a subsurface plumbing systemthat can be difficult to unravel.

What can ultimately be produced is impossible to pre-dict, but if the average recovery factor for each reservoirclass can be improved, it is possible to calculate a range ofpossibilities. For the case in which average recovery factorsin each reservoir class are increased to an 'ideal' level,based on results in the better fields, the incrementalincrease over current projections are BS-5.9%, CS-10%,and FDD-8.8%. This yields an incremental recovery of over7.5 BBO, or about half the current State EUR. Althoughtechnically possible, this is shown only for comparisonand is not considered realistic. Though, when startingwith a remaining OIP of 68 BBO, even very modestimprovements to average recovery factors generate largevolumes of incremental oil. This is illustrated in the min-imum case scenario in which the average net improve-ments in recovery factor over current projections are: BS-

Figure 16: Table showing incremental oil recoveries given three possible increases in average recovery factor for three reservoir classes.


0.9%, CS-2.5%, and FDD-1.3%. In this example, where allrecovery factors are significantly below levels that are rou-tinely achieved in the better managed fields, the incre-mental volume of producible oil is still a staggering 1.4BBO (Fig. 16).

RecommendationsIt is fitting, as the State begins its second century,

that a concerted effort be initiated to revitalize produc-tion of the resource that led to Statehood. To accomplishthis, steps must be taken to enable operators to identifywhere it is possible to economically recover oil that willotherwise be left in the ground.

DataOklahoma's historically hands-off attitude towards oil

and gas data has created a situation in which service com-panies and geologic societies have become the main repos-itories for these data. A program called Energy LibrariesOnline Inc. (ELO), founded by the Oklahoma CityGeological Society and The Oklahoma Well Log Library, isnow underway. This online reference library will eventual-ly contain scanned images of virtually all of the hard-copydata now housed in these two libraries. Ultimately theonline library will also include the State oil and gas datathat is maintained by the Oklahoma Geological Survey atthe Oklahoma Petroleum Information Center.

Even the best organized and maintained hard-copycollections cannot compare to digital databases. In addi-tion to their ability to archive irreplaceable documents,they bring together the many, disparate data elementsthat earth scientists need to evaluate oil and gas in thesubsurface. The ELO database will put in one place scoutcards, completion data, well logs (including geologicalsample logs, strip or driller's logs, electrical logs, and mudlogs), and production data. It is important to organize andarchive all subsurface data in one place, but one of themost important benefits the ELO system will bring to oper-ators seeking to identify underperforming oil reservoirswill be access to early production data, scout cards andstrip logs, which today is difficult to impossible.

With such persuasive evidence that recovery factors ina significant percentage of the State's oil fields are sub-standard, little more needs to be done than to give theindustry the tools it needs to find it. If these data increaseoil-targeted drilling and production activity, every facet ofthe State economy will receive a boost. However, the ben-efits of a fully functioning online library extend wellbeyond the oil and gas industry. The ELO effort will alsoassist Oklahoma scientists in other areas of vital research,such as the study of groundwater resources and environ-mental quality.

ProductionThe lack of early production data is a major roadblock

to operators seeking to revive old fields. IHS Energy dataare severely handicapped by the nearly two billion barrelsof missing production mentioned previously, and monthlydata that begins in 1970. The inability to obtain monthlyproduction data from inception, and thereby reliablyassign cumulative production on a lease basis, is one ofthe largest impediments to finding substandard recoveriesand thereby producing additional oil. Drilling and second-ary/enhanced recovery activity is easy to identify withcomplete monthly production data. However, because 70%of Oklahoma's oil was produced before 1970, in most of thefields that were examined the 'beginning cum' numberdwarfs the volume on which monthly production is shown.Thus, the production curve usually shows little more thanthe tail of a decline that began long before 1970.

Complete production data do exist on microfilm andmicrofiche at the Oklahoma Tax Commission, but theserecords also include confidential tax data, and thereforeare unavailable for large-scale, public use. (Limited leaseproduction requests can be filled on a case by case basisby OTC personnel.) Hard-copy monthly lease productiondata from 1935 have been available at the Oklahoma Cityand Tulsa Geological Society libraries in their collectionsof Vance Rowe production books. These monthly produc-tion values will be hand-entered into a digital databaseand be available online through the ELO system.

Because Vance Rowe production begins nearly 40 yearsafter production began in Oklahoma, these data will notcompletely solve the State's oil production issues, but theywill vastly improve the situation. They will help put 75%of the State's total oil production into a monthly frame-work, and hopefully find a home for much of the missing2 BBO of production. This will make it possible to reviewdetailed production histories and verify cumulative pro-duction for many more fields than is possible now. It willalso make it possible to calculate reliable recovery factorsand more easily identify and high-grade improved oilrecovery candidates. Without reliable production data anoperator runs the risk, especially in an older field, thatthe incremental oil being sought has already been pro-duced.

Strip or Driller's LogsThe Oklahoma Geological Survey is the final stop for

most of the hard-copy data used by the State's oil and gasindustry. In addition to the hard-copy 1002A forms, it isalso the repository for the electric logs submitted by oper-ators to the State. It is estimated the Survey has paperelectric logs for about 365,000 wells. Most of these areavailable through service companies in digital format.However, a key dataset that has been unavailable to theindustry is the State's collection of approximately 125,000hand-plotted driller's strip logs. If all goes well, these willalso be available online in the near future.

In the days before rotary drilling and the requirement


for drilling mud, wells were drilled using cable tool rigs.Cable tool wells have only air in the hole, creating anessentially continuous DST in which anything less thanoil-to-surface was considered a dry hole. Most of thesewells were drilled before the advent of electrical logs, socable tool drillers recorded the subsurface formations pen-etrated on what is called a driller's log. These logs, withcomments, were later plotted by students or geologists onblank strip logs. These logs vary in what they contain andthe detail in which it is recorded, but most record depth,lithology, fluid type, shows and initial potential. For someof these, there is no API number or well spot, making asingle, narrow strip of yellowing paper virtually the onlyrecord of that particular well.

Rotary drilling was developed in the late 1920s andbecame the dominant drilling technique by the mid-1930s.Although the evolution to rotary drilling was gradual, ifone assumes that every well drilled prior to January 1,1935 was drilled with a cable tool rig, then about 104,000Oklahoma wells, of which 62,000 were oil wells, weredrilled using cable tool rigs (IHS Energy, 2008). Based onthis, strip logs represent the only subsurface data for overone quarter of the State's oil wells and one fifth of all ofthe wells ever drilled. While these do not have the utilityor resolution of electrical logs, when used with more mod-ern logs they can dramatically improve subsurface control.This is especially true in areas where early drilling pre-dominates, which includes every major area where oil isproduced. It is not known how many of the early cabletool wells are represented in the combined strip log col-lections of the OCGS, TGS and the OGS. This is becauseduplicates were created when more than one geologistlooked at the cuttings. However, between the Survey'sroughly 125,000 and the Tulsa and Oklahoma City library's100,000, the majority should be represented.

OperatorsThe recommendation to operators is simply: "Don't

give up on oil." Poor field management in the early days,complex reservoirs, diverse ownership, and a lack of basicwell and production data have combined to leave, even atthis late stage in the industry, large quantities of move-able oil in many reservoirs. If the studies evaluated in thisarticle are indicative of those throughout the State, theeconomically remaining producible oil volume is verylarge. The primary hurdle, and it will remain a large one,is in identifying it. After that, the techniques recom-mended here for its production tend to be decidedly low-tech: new wells, water in the ground in new or modifiedwaterfloods, or water out of the ground in dewateringoperations.

A great deal of the secondary recovery work done thusfar has been piecemeal. Except in the largest fields, therehas been little coordination between operators andundoubtedly little detailed, field-wide reservoir simulation

work. A map of the waterflood unit boundaries in the NRISdatabase (those active since 1979) shows an irregularpatchwork of secondary recovery projects that overlay lessthan half of currently producing oil leases in Oklahoma.Based on the field studies carried out by the OGS, many ofthese waterflood units have been subdivided into smallerareas that are operated in isolation and at cross-purposeswith the management of adjacent units. In the survey offield studies in this review it was found that many hadmuted and/or delayed responses to injection, clearlyshowing that sweep efficiency was poor.

A technique that has shown promise in some clastic,and especially carbonate dual-porosity reservoirs is called'de-watering'. It works best in fractured rocks with lowmatrix permeability where there is significant down-dipwater, but it can also be effective in clastic reservoirs withthick transition zones or where high and low permeabilityzones are juxtaposed. Such reservoirs often have very lowrecovery factors because only the oil stored in the highpermeability part of the dual porosity system (usually sec-ondary porosity) is drained. After this the oil rate dropsdramatically, with little loss in reservoir pressure, as waterrises through the reservoir. Although the lower permeabil-ity (matrix) component of the reservoir is still largelyundrained, most operators will give up at this point.However, with sufficient water pumping and disposalcapability one can reduce the reservoir pressure until theassociated gas in the unproduced oil expands. This oil canthen be pushed into the fracture system and ultimatelythe wellbore. In West Carney Field the dewatering tech-nique took a Hunton (CS) reservoir with cumulative pro-duction of just 38 MBO and 0.5 BCF to one with reservesof 2.2 MMBO and 16 BCF (Chernicky, 2002a). A number ofthe low recovery CS reservoir field studies showed produc-tion curves strongly suggestive of a dual porosity systemthat might lend them to this recovery technique.

New Dominion L. L. C., a leader in the de-wateringtechnique, has also had success in a Red Fork (FDD) reser-voir in Mount Vernon Field. Here aggressive water produc-tion and the resulting drop in reservoir pressure hasallowed associated gas in intervals of low permeability andhigh water saturation to push oil into larger pore systemsand fractures. In this field incremental recovery wasincreased 1.26 MMBO + 18.5 BCF + 1.77 MMBC (Chernicky,2002b).

There are a variety of more exotic improved recoveryoptions that may be viable in selected areas. The injectionof gas, microbes, detergents, surfactants, as well as in-situcombustion techniques have all been applied with varyingdegrees of success. CO2 injection has received much pressrecently, often in the dual role of both oil enhancementand sequestration. However, while there are a handful offields in which CO2 is being used successfully to enhanceoil recovery, its widespread use should be viewed with cau-tion. Because of the many old and undocumented wells in


most of the oil producing areas of the State, issues ofcross-flow into other reservoirs, including aquifers, as wellas surface leakage will likely be persistent problems.

Any systematic effort to identify underachieving oilreservoirs in Oklahoma will be manpower intensive andrequire collaboration between engineers, geologists, andlandmen. Areas where original operator records are avail-able (especially those showing pressures and water pro-duction) are ideal, but certainly in most areas an incom-plete data set will add an element of risk to any improvedrecovery project. Drilling, log, completion, and productiondata for Oklahoma are scattered, with some existing onlyin hard-copy. Access to these data will be greatly facili-tated with the completion of the ELO system, which willbring the OCGS and TGS library's hard-copy data to oneplace, in a digital format. Even more important will be theaddition of two major datasets that are not yet accessible,but critical to the effort described in this report. These arethe Vance Rowe production data, that will push monthlyproduction records back to 1935, and the State's majorstrip log collections. ELO will help to fill critical gaps inour knowledge and greatly facilitate the search for under-achieving oil reservoirs.

ConclusionsOil production in Oklahoma has fallen almost continu-

ously since 1984, with record prices in the last severalyears having a minimal affect on the long-term decline.Although large oil discoveries are no longer possible, hugevolumes of producible oil are waiting in thousands ofexisting fields. Early production practices (which allowedfor the flaring of 3-6 TCF of associated gas), fragmentedownership, and a variety of complex reservoirs will com-bine to leave 81% (68 BBO) of the State's OOIP in theground at abandonment. A review of the geologic litera-ture shows examples of low recovery that can be addressedrelatively simply, through waterfloods, modified water-

floods, de-watering, new wells and/or re-completions. Historically haphazard production reporting and data

dissemination has greatly complicated efforts to system-atically evaluate oil possibilities in Oklahoma. However,while this has discouraged operators from evaluating oilpossibilities in the past, it has also helped to create thecurrent opportunity. As data issues are addressed and thelong-term price of oil rises, as it surely must, a large-scalere-evaluation of Oklahoma's oil reservoirs is inevitable. Theresults of such an effort have the potential to extend thelife of meaningful oil production for decades beyond cur-rent estimates, and directly and indirectly benefit everyarea of the State.

There is no shortage of challenges associated withsuch an undertaking, but if the studies reviewed here arein any way representative of the State as a whole, the oilvolumes and potential rewards for the State and the indus-try are enormous. The volume that may be recoverablethrough a wide-scale effort is impossible to predict, butevery 1% of the remaining oil in-place represents a stag-gering 680 MMBO of incremental recovery. At $75 per bar-rel (excluding associated gas production) every 100 MMBOproduced represents $7.5 billion in total income and $525MM net to the State in gross production tax revenues.What are we waiting for?

AcknowledgementsThe author would like to thank the IHS Energy Group,

who provides the Oklahoma Geological Survey the free useof their database, which greatly facilitated the completionof this study. A debt of gratitude is also owed Roy Knapp,professor of petroleum and geological engineering at theUniversity of Oklahoma College of Earth and Energy, andTim Brown, executive director of Energy Libraries Online,who had useful ideas that were incorporated into thisstudy.

ABOUT THE AUTHORDAN T. BOYD

Dan Boyd is a petroleum geologist with the Oklahoma Geological Survey, where he has been employed since2001. Dan received his Master of Science degree in geology from the University of Arizona in 1978. He spent thefirst 22 years of his career as an exploration and development geologist in the petroleum industry. From 1978through 1991 he worked on a variety of areas in the United States from Houston, Dallas, and Oklahoma City forMobil Oil and Union Texas Petroleum. In 1991 he moved overseas, working in Karachi Pakistan for four years andJakarta Indonesia for the following four. He returned with his family to the U.S. in 1999 with Arco (the succes-sor to Union Texas) where, until Arco's sale to BP, he worked on the offshore Philippines from Plano, Texas. Henow enjoys a more settled life in Norman, Oklahoma with his wife and two children. Dan is a history buff, ama-teur astronomer, and violinist in the OU Civic Symphony.

Since joining the Staff of the Oklahoma Geological Survey in 2001, Dan has been involved in updating the Oiland Gas Map of Oklahoma in 2002 and preparing and presenting several published reports on the history, status,and future outlook of the oil and gas industry in Oklahoma. He chaired the 2002 Symposium on CherokeeReservoirs in the Southern Midcontinent and edited the attendant publication, OGS Circular 108. Dan also pre-pared and presented his report on the Morrow-Springer gas in Oklahoma for the 2005 Springer Gas PlaySymposium. Dan recently prepared and presented, with others, the study on the Booch gas play in southeasternOklahoma and the subsequent OGS Special Publication 2005-1.


PUBLISHED REFERENCES

(The Oklahoma City Geological Society(OCGS), and the Shale Shaker EditorialBoard, are not responsible for omissionsof references cited in the text.)

Boyd, D. T., 2002a, Oklahoma oil: past,present, and future: OklahomaGeology Notes, v. 62, no. 3, p. 97-106.

----, 2002b, Map of Oklahoma oil and gasfields (distinguished by GOR andconventional gas vs. coalbedmethane): Oklahoma GeologicalSurvey Map GM-36, 1 sheet, scale1:500,000.

--------, 2005, Oklahoma Oil and GasProduction: Its Components andLong-term Outlook: OklahomaGeology Notes, v. 65, no. 1, p. 4 - 23.

Chernicky, D. and Schad, S. T., 2002a,Hunton Transition Zone inOklahoma: A Case Study in WestCarney Field, Lincoln County,Oklahoma Geological Survey Circular107, pp. 179.

Chernicky, D. and Schad, S. T., 2002b,Development of Transition ZoneReserves Around AbandonedProduction: Case Study of MountVernon Field, Lincoln County,Oklahoma, Oklahoma GeologicalSurvey Circular 108, pp. 61-72.

Claxton, Larry (ed.), 2007, Oil and gasinformation: Oklahoma CorporationCommission, Web site:http://www.occ.state.ok.us/Divisions/OG/annualreports.htm

E.I.A., 2005, U.S. Crude Oil, Natural Gas,and Natural Gas Liquids ReservesAnnual Report, Web site:http://www.eia.doe.gov/neic/infos-heets/petroleumreserves.htm

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IHS Energy, 2008, Data supplied byPetroleum Information/Dwights LLCdba IHS Energy Group, August 1,2006, all rights reserved.

Knapp, Roy, 2006, Professor, Petroleumand Geological Engineering,University of Oklahoma, personalcommunication.

U.S. Department of Energy, 1984, TORIS(Total Oil Recovery InformationSystem), National Energy TechnologyOffice, Tulsa, Oklahoma

U.S. Department of Energy, 1993, Oiland Gas Technology TransferActivities and Potential in EightMajor Producing States, Vol. 1, per-formed under contract No. FG22-91BC14818 for the Interstate Oil andGas Compact Commission OklahomaCity, Oklahoma, 13p.

Appendix : Listing of Volumetric Studies

Original Field Name Reservoir Name Date Author

Blanket Sandstone_____________________________________________________________________________________________________________________________________Aylesworth Dist SE Oil Creek 1994 Roger SpringCentrahoma McLish 1975 W. P. AndersonCentrahoma Oil Creek 1994 Roger SpringCoyle SE Wilcox 1994 Robert TehanCriner -Payne Bromide 1963 Lloyd GatewoodDavis SW Oil Creek 1981 Thomas CurrentEola-Robberson McLish 1981 Bill Harrison compilerEola-Robberson Oil Creek 1981 Bill Harrison compilerEola-Robberson Bromide 1981 Bill Harrison compilerHunter S Misener 1979 Mike KernanMadill N Bromide 1965 Joseph KornfeldMadill N McLish 1994 W. E. JacksonNoble NW Tulip Creek 1994 Harry BuckNoble NW Oil Creek 1994 Harry BuckNoble NW McLish 1994 Harry BuckNoble Townsite Tulip Creek 1994 Paul SmithNoble Townsite Bromide 1994 Paul SmithOconee E Oil Creek 1973 Don MorrisOklahoma City Wilcox 1968 Lloyd GatewoodOklahoma City Oil Creek 1968 Lloyd GatewoodPrague W Wilcox 1994 Lee LamarRich Valley Wilcox 1963 D. W. BellWashington N Bromide 1994 Paul SmithWashington N Tulip Creek 1994 Paul Smith

Carbonate Shelf_____________________________________________________________________________________________________________________________________Buffalo N Lansing 1963 B.D. PriceBuffalo N Arbuckle 1963 B.D. PriceCentrahoma Viola 1975 W. P. AndersonCheyenne Valley Hunton (Henryhouse) 1994 Kathy LippertCottonwood Creek Arbuckle (Brown Zone) 1994 David ReadCriner -Payne Hunton 1963 Lloyd GatewoodDibble SE Hunton 1963 Harold MeullerDover-Hennessey Manning 1963 John WareDover-Hennessey Meramec 1963 John WareEdmond W Hunton 1981 Bill Harrison compilerFitts Viola 1981 Bill Harrison compilerIsom Springs Arkansas Novaculite 1981 L.S. Morrisson


Lincoln Oswego 1962 Charles DurhamMustang (partial) Hunton (Bois d'Arc) 1973 William LondonMustang (all) Hunton (Bois d'Arc) 1995 Robert HoNoble NW Viola 1994 Harry BuckNoble Townsite Viola 1994 Paul SmithOklahoma City Arbuckle 1968 Lloyd GatewoodPrague W Hunton 1994 Lee LamarPutnam Oswego 1963 Donald BrownRich Valley Miss Chat 1963 D. W. BellRosenwald Union Valley 1957 M. R. SmithShalom Alechem Sycamore 1974 Lee R. RileySooner Trend Meremec-Osage 1975 S. A. HarrisWashington N Viola 1994 Paul Smith

FDD_____________________________________________________________________________________________________________________________________Alamo SW Osborn 1994 Marion HutchinsonAllen Gilcrease 1981 Bill Harrison compilerAllen (partial) Booch 1981 Bill Harrison compilerAllen (partial) Booch 1981 Bill Harrison compilerAntioch SW-Elmore City N Gibson 1948 Marshall DaytonBalko S Morrow (A) 1995 Rick AndrewsBinger E Marchand 1980 Louis FordBlackwell Tonkawa 1997 Kurt RottmanBlackwell Lake E Osage-Layton A 1996 X. YangBlackwell Lake E Osage-Layton B 1996 X. YangBlackwell Lake E Osage-Layton C 1996 X. YangBlackwell Lake E Osage-Layton D 1996 X. YangBoyd Morrow (Upper) 1961 Panhandle Strat committeeBurbank S Burbank 1963 T. A. MatthewsButner NW Senora 1958 James DuckCanton Lw Morrow B & C 1995 Rick AndrewsCarmen N Red Fork 1997 Rick AndrewsCement Noble Olsen 1981 Bill Harrison compilerCement Fortuna 1981 Bill Harrison compilerCement Wade 1981 Bill Harrison compilerCement Medrano 1981 Bill Harrison compilerCherokee NE Red Fork 1963 Eugene F. CulpCoyle SE Skinner 1994 Robert TehanCushing Prue 1981 Bill Harrison compiler



Dibble N Osborn 1974 Gene JearyDora Dora Sd 1941 W. I. InghamElmwood W Morrow 1963 John DowdsEola-Robberson Skaggs Sand 1981 Bill Harrison compilerEva NW Kelly Sand 1961 W. W. WilliamsFitts W Cromwell 1981 Bill Harrison compilerFlat Rock Bartlesville 1954 C. H. RiggsGlencoe SE Red Fork 1994 Chris FowlerGlenn Pool Glenn Sand 1994 Kuykendall, MatsonGolden Trend Hart 1981 Bill Harrison compilerGreasy Creek Booch 1995 Bob NorthcuttGriggs S Wichita Sand 1961 Lloyd Pippin - Leland PolingGriggs S Wolfcamp (Winfield Sd) 1961 Lloyd Pippin - Leland PolingGuthrie SW Skinner 1996 Kurt RottmanHealdton (partial) Healdton Sand 1981 Bill Harrison compilerHealdton (all) Healdton Sands 1953 C. H. Riggs et alHiggins S Morrow 1994 Robert TehanKatie Gibson 1949 Chandler, William A Lake Blackwell E Osage-Layton 1996 Jock CampbellLayton Sand Unit Layton 1972 James PateLong Branch Prue 1996 Rick AndrewsLong Branch Red Fork (ch-fill) 1997 Rick AndrewsLong Branch Red Fork (other) 1997 Rick AndrewsMcQueen SW Swastika 1994 W. E. JacksonMount Vernon (B) Red Fork 2002 David Chernicky


Mount Vernon (comb) Red Fork 2002 David ChernickyMuskogee Muskogee 1959 C. H. RiggsNorge NW-Verden Marchand 1974 T. B. CurleeOakdale Red Fork 1968 Gustavo Gonzalez-P.Ohio-Osage Bartlesville 1997 Andrews-NorthcuttOklahoma City Prue 1981 Bill Harrison compilerOtoe City S Red Fork 1997 Kurt RottmanParadise Bartlesville 1997 Rick AndrewsPauls Velley E Burns-Brundidge 1949 Frank FolgerPerry SE Skinner 1996 Kurt RottmanPerry Townsite Skinner 1993 S. B. ClinePleasant Mound Cleveland 1997 Kurt RottmanQuapaw Bartlesville 1952 James WestReck Deese Basal 1994 J. T. BoyceRice NE Purdy "C" 1995 Rick AndrewsRice NE Purdy "B" 1995 Rick AndrewsRosenwald Cromwell 1957 M. R. SmithRussell NW Bartlesville 1997 Rick AndrewsSalt Fork N Skinner 1996 Rick AndrewsSalt Fork SE Skinner 1963 W.R. SumterSivells Bend Beasley 1958 Bracken, Barth W.Sturgis E Purdy Sd 1961 W. W. WilliamsTecumseh NW Red Fork 1994 Fletcher LewisUnity N Keyes Sd 1961 W. P. BuckthalWewoka NW Booch 1995 Kurt Rottman

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