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ABSTRACT

Mission Canyon oil production on the south flankof the Williston basin provides an example of anarea in the mature stage of exploration that showssignificant hydrodynamic effects on oil accumula-tions related to stratigraphic traps. The effects areillustrated by the Billings Nose fields and theElkhorn Ranch field. The reservoirs have lowhydraulic gradients of about 2 m/km (10 ft/mi), tiltedoilwater contacts with gradients of 5 m/km (25ft/mi), and variable formationwater salinities thatrange from brackish to highly saline. Oil accumula-tions in some zones are displaced off structure anddowndip to the northeast, parallel to porosity pinch-outs. Other zones are pure hydrodynamic traps,lacking both structural and stratigraphic closure.Future success in exploration and development inthe play will depend on recognizing the hydrody-

namic effects and predicting oil displacement.

INTRODUCTION

Hydrodynamic flow of formation water affects oilaccumulations in structural and stratigraphic traps.Freshwater can invade the porous zones and dilute

the normally saline formation water. Flow can adisplace the oil in a downstream direction causdistinct tilts in the oilwater contacts (Hubbert, 19Berg, 1975). Variable water salinities and displacedaccumulations present problems of well log interptation and selection of locations for exploratory adevelopment wells in hydrodynamic settings.

The possibility of hydrodynamic conditions in Williston basin (Figure 1) was first suggested by Mray (1959) based on tilted oilwater contacts in toil fields. Regional flow patterns were later estlished by studies of the Mississippian Madisaquifer (Downey, 1984), which includes the princreservoir zones of the basin. The effects of flow well illustrated by oil fields within the greater BilliNose area of the south-central part of the basin.

The Williston basin is a prominent cratonic bain the north-central United States, and large oil fiewere first discovered in 1951 along the Nesson a

cline and soon afterward in Saskatchewan. Mulater, the discovery of two large oil fields in south-central part of the basin, Little Knife and Billings Nose fields, led to extensive developmdrilling that confirmed the occurrence of tiloilwater contacts in several fields.

The effects of flow were not obvious during early stage of drilling, and stratigraphic chanwere interpreted to be the principal trapping mecnism in Mission Canyon reservoirs of the MadisGroup. This conclusion resulted in an emphasisresearch on the Mission Canyon facies, and numous papers have addressed the stratigraphy and rproperties in the Billings Nose area (Altschuld a

Kerr, 1982; Kupecz, 1984; Breig, 1988) and LiKnife field (Wittstrom and Hagemeier, 1978; Lindand Roth, 1982; Narr and Burruss, 1984; Lindsay aKendall, 1985; Lindsay, 1987). A review of reservcharacteristics and stratigraphic relationships acrNorth Dakota was provided by Lindsay (1988). Tstratigraphic model involves thin, porous bedsdolomite that grade updip by facies changes itight evaporites, similar to stratigraphic traps el

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Copyright 1994. The American Association of Petroleum Geologists.All rights reserved.

1Manuscript received, February 9, 1993; revised manuscript received,November 29, 1993; final acceptance, January 3, 1994.

2Department of Geology, Texas A&M University, College Station, Texas

77843-3115.3Marathon Oil Co., P.O. Box 3128, Houston, Texas 77253.4Dupont Environmental Remediation Services, 140 Cypress Station,

#140, Houston, Texas 77090.The present manuscript was compiled by Berg and DeMis from detailed

field studies. The Billings Nose fields were interpreted by Mitsdarffer for theMaster of Science degree in geology at Texas A&M University. Drill-stem testreports for the area were provided by Roger Hoeger, Denver. Elkhorn Ranchfield was studied by DeMis while employed by Pennzoil, and permission topublish the results is gratefully acknowledged. The manuscript was improvedby the critical comments of John M. Parker and AAPG reviewers KennethBird, Robert Lindsay, and Mark Longman.

Hydrodynamic Effects on Mission Canyon(Mississippian) Oil Accumulations, Billings Nose Area,North Dakota1

Robert R. Berg,2William D. DeMis,3 and Alan R. Mitsdarffer4

AAPG Bulletin, V. 78, No. 4 (April 1994), P. 501518.

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where in the basin. An excellent summary of thereservoir properties, stratigraphy, and facies of theMission Canyon of the Billings Nose area was pre-sented by Petty (1988), but the importance of hydro-dynamic flow was not described (DeMis, 1990).

Although the stratigraphic model applied to somereservoirs in the area, it soon became apparent thatoilwater contacts were not everywhere horizontal

and that hydrodynamic flow could be a factor in thelocation of oil accumulations (Mitsdarffer, 1985;DeMis, 1987, 1992; Breig, 1988). The purpose of thispaper is to document the hydrodynamic conditions,describe the effects of flow on oil accumulations, andshow that hydrodynamic principles can be applied toexploration for additional oil in this mature area. Theconclusions of this study apply to other basins wherelow-gradient, hydrodynamic flow is present.

DEVELOPMENT HISTORY

Mission Canyon fields in the south-central Willis-ton basin have been discovered over the past 30 yr.With the first discovery of Mississippian oil on theNesson anticline in 1951 (Figure 1) and subsequentdiscoveries in Saskatchewan, exploration spreadthroughout the Williston basin. The first field in theBillings Nose area was Fryburg, discovered in 1953by Amerada (Table 1). In the late 1950s, Shell Oilundertook an extensive analysis of the MissionCanyon formation. Shell geologists defined a strati-graphic play in which porosity trends were terminat-ed updip by anhydrite. Geophysicists mapped abroad anticline they called the Medora Nose (laterknown as the Billings Nose), and a dozen wildcatwells were drilled during the late 1950s and early1960s in search of the pinch-out traps.

This early attempt to define stratigraphic traps wasan outstanding example of insightful geologyapplied in a sparsely drilled areaand bad luck.Only one small, marginally economic MissionCanyon field, called Rough Rider, was discovered in1959. Later drilling in the greater Billings Nose areaproved in-place reserves on the order of 250 millionbbl. Many of these fields have Shell dry holes offset-ting the producing area. For example, the discoverywell in Elkhorn Ranch field was drilled by Shell in1961 and tested oil in the Mission Canyon but wascompleted in the deeper Bakken shale for 100

bbl/day. This single well was still producing 50bbl/day when the casing collapsed in 1965, and thewell was plugged and abandoned.

Elkhorn Ranch field was rediscovered in 1974when Cenex offset the original Shell well by one-fourth mile and completed the new well in the Mis-sion Canyon formation. Further development wasslowed, however, because the hydrostatic modellimited the number of possible locations to the high-

est part of the structure. Finally, the field wasextended in the early 1980s when the hydrodynamicinfluence on the trap was recognized (DeMis, 1990).

In late 1977, Gulf Oil Company tested a largestructure in easternmost Billings County and discov-ered Little Knife field (Wittstrom and Hagemeier,1978). Subsequently, a number of discoveries weremade in central Billings County, and developmentlinked these fields into one large and essentially con-

502 Mission Canyon Fields, North Dakota

Figure lRegional structure and location of the Willis-ton basin. (A) Structure on top of the Mission Canyonformation showing the location of important oil fields(black) and the greater Billings Nose area. Contourinterval is 305 m (1000 ft). Map modified from Hansen(1972). (B) Location of the Williston basin in the north-central United States and the location of uplifts whereMississippian rocks are exposed to recharge by mete-oric waters: BH, Black Hills; BM, Bighorn Mountains.

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tinuous producing area now called the Billings Nose(Breig, 1988). During development, brackish forma-tion water of 15,000 ppm NaCl was recovered ontests at the southwest end of the producing area, andthis water contrasts with salinities of greater than100,000 ppm NaCl normally found in the MissionCanyon. Consequently, a study of fluids and pres-sures was undertaken to determine the reason forthe salinity differences (Mitsdarffer, 1985). At thesame time, tilted oilwater contacts were detected atElkhorn Ranch (DeMis, 1987) and at Knutson field(Bogle and Hansen, 1987).

MADISON HYDROLOGY

A regional study established the hydrodynamicconditions for the Madison aquifer over a broad area(Downey, 1984). The aquifer is recharged by meteoricwaters in outcrops around the Black Hills uplift onthe south and the Bighorn Mountains on the south-west at surface elevations greater than 1220 m (4000ft) (Figure 2A). A map of the freshwater potentiomet-ric surface indicates that the flow of formation water

is generally eastward across the Williston basin, butthe potentiometric gradient is low. For example, thehead at Mondak field in western South Dakota (Fig-ure 1) is about 1070 m (3500 ft), and discharge fromthe aquifer takes place 320 km (200 mi) to the eastalong the truncated edge of the aquifer (Figure 2A) atelevations of about 460 m (1500 ft). The head differ-ence of 610 m (2000 ft) in a distance of 320 km (200mi) gives a regional gradient of only 2 m/km (10

ft/mi).Madison formation water ranges from nearly fr

close to the outcrops to brines of 300,000 ppm Nin the central basin (Downey, 1984) (Figure 2B). Tpattern of salinity change suggests that the inflowmeteoric water has diluted the normally saline waof the basin. Tongues of brackish water extend frthe south and southwest almost to the Billings Narea. It is in this regional setting that the effectsflow can be detected in oil accumulations.

LOCAL GEOLOGY

Most of the basin is characterized by gentle dof about 4.7 m/km (25 ft/mi), and the only mastructures are the Cedar Creek and Nesson anticli(Figure 1). Minor structures in the south-central pof the basin are the north-plunging Little Knife acline and the broad, north-plunging Billings N(Figure 3). The five principal fields, in order of dcovery, are the Fryburg, Rough Rider, ElkhRanch, Little Knife, and Billings Nose fields (Ta1). With the exception of Little Knife, there are

structural closures. Oil accumulation appears tolargely independent of structure as shown by producing area that extends across the shallow scline between the Tree Top and Big Stick fields.

The Mississippian Madison Group has produmost of the oil in the basin, and the Mission Canyformation contains the principal reservoirs. Limstones and dolomites of the Mission Canyon gralaterally to anhydrites, and the formation is under

Berg et al.

Table 1. Mission Canyon Oil Production from Selected Fields, Greater Billings Nose Area, South-Central WillisBasin, North Dakota

Cumulative Production(to April 1992)

Oil GasField Discovery Wells (million bbl) (bcf)

Fryburg 1953 27 10.2 0.8

Rough Rider 1959 35 12.9 9.5Medora 1964 24 5.5 0.1Elkhorn Ranch 1974 65 20.3 23.0Little Knife 1977 179 58.0 100.0Billings Nose fields

Big Stick 1978 61 43.1 44.5Four Eyes 1978 10 4.0 1.7T-R 1978 36 7.5 4.6Tree Top 1978 34 10.2 8.9Whiskey Joe 1979 28 5.3 3.4Subtotal (Billings Nose) 70.1 63.1

Lone Butte 1981 22 5.5 11.6Knutson 1983 16 4.0 0.6

Totals 186.5 208.6

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by dense lime mudstones of the Lodgepole forma-tion and overlain by anhydrite and halite beds of theCharles Formation.

Subdivisions of the Mission Canyon are given infor-mal member names to designate timerock units (Carl-son and LeFever, 1987). However, the subunits are dif-ficult to correlate across the basin, and stratigraphicnames have not been used consistently. Therefore, wehave adopted the nomenclature of Petty (1988) for thisarea. In the south-central part of the basin, the MissionCanyon section is called the FrobisherAlida interval,and the reservoir zones are in the Bluell, Sherwood,and Mohall submembers (Figure 4). In Big Stick field,letter designations were used for these zones. The Fro-bisherAlida interval in the southern Williston basincontains three principal porous zones that pinch outtoward the southeast and are successively older in thatdirection (Figure 3). Oil production is generally fromthe highest porous zones immediately below the Nes-

son anhydrite. Each porous zone is contained within ashoaling-upward sequence deposited during a majorregression. The sequences consist of (1) open marine,low-porosity, skeletal packstones that grade upward to(2) subtidal, dolomitized, higher porosity skeletalmudstones and wackestones, and culminate in (3)intertidal, porous, stromatolitic mudstones. The inter-tidal deposits grade updip to the southeast intosupratidal, tight, anhydritic dolomites (Altschuld and


Figure 2Regional maps of the Mississippian Madison aquifer in the Williston basin and adjacent areas (fromDowney, 1984). Study area is the greater Billings Nose area (see Figure 1). (A) Freshwater potentiometric surfaceshowing generally eastward flow across the Williston basin. Contours are isopotentials (in feet above sea level);contour interval is 61 m (200 ft). Black arrows indicate flow directions normal to isopotential contours. (B) Forma-tion water salinity showing nearly freshwater around the recharge areas of the Black Hills and Bighorn Mountainsand the brine area (cross hatched) in the central Williston basin. Contours are in parts per million (ppm) of totaldissolved solids; contour interval is variable.

Figure 3Regional structure of the greater Billings Nosearea on top of the Mission Canyon formation showing thenortheastern trends of porosity in the FrobisherAlidainterval and pinch-out of successively older zones towardthe southeast. Contour interval is 30 m (100 ft). Shadedareas are fields that produce oil from Mission Canyonreservoirs. Small circles represent wells in which drill-stem tests give original pressures by extrapolation ofpressure buildup and also measurements of formation

water resistivities.

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Kerr, 1982; Lindsay and Roth, 1982; Kupecz, 1984;Petty, 1988). These sequences are repeated severaltimes within each of the submembers. Porous zonesare thin and range from 0.6 m (2 ft) to 6 m (19 ft).Reservoir properties are highly variable and have beensummarized for several fields (Petty, 1988). An impor-tant conclusion from these measurements is that thelower limit for water-free oil production is about 1 md,which corresponds to porosities of 10 to 15%, depend-ing on the producing zone and rock type.

METHODS OF STUDY

Two principal data sets are required to define thehydrogeology of any oil field: (1) original fluid pres-sures before drawdown by production and (2) fluidproperties. In the Billings Nose fields (Mitsdarffer,1985), initial pressures were obtained by extrapola-tion of pressure buildup during drill-stem tests(Horner, 1951). More than 300 tests were examined,and 60 tests were selected as having reliable extrap-

olations of pressure buildup as well as adequdetails of fluid recoveries. These pressures and waproperties were used in regional mapping.

In the Billings Nose fields, formation water retivities (Rw) were obtained from well log interpretions. Graphs were made of true resistivities (Rt) afunction of porosity () (Pickett, 1966) to obtwater-saturated resistivities (Ro) that were extrapoed to apparent water resistivities at = 100% (Fig5). The extrapolations assumed that both the cemtation exponent (m) and the saturation exponent were equal to 2. The reliability of the grapmethod was checked against resistivities of wat

recovered from drill-stem tests and during comption. Water resistivities were then convertedequivalent NaCl salinities at an average reservtemperature of 115C (240F).

Pressures measured in the oil column were corred to those which would be measured in a water umn at the elevation of measurement using an averoil gravity of 40 API and reservoir density of 0.g/cm3. In most cases, the correction was neglig

Berg et al.

Figure 4Well log correlation section of the upper Mission Canyon formation across the Billings Nose area shing the step-down of major producing zones in the FrobisherAlida interval and the thickening of the Nes

Anhydrite toward the southeast. Interval names are from Petty (1988); locations of fields shown in Figure 3. Datis the gamma marker at the base of the Lower Sherwood interval. No horizontal scale. Well logs are gamma (GR), density porosity (D), and neutron porosity (N).

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small. Hydraulic heads were calculated from the initialpressures using a freshwater gradient of 9.8 kPa/m(0.433 psi/ft) in areas of brackish formation waterabove an elevation of 2073 m (6800 ft). Heads werecorrected for saline formation waters below 2073 m(6800 ft) using a gradient of 10.5 kPa/m (0.465 psi/ft).The correction for saline water resulted in small reduc-tions in heads that would be calculated by using a sin-gle freshwater gradient for the entire area.

At Elkhorn Ranch field, a study of the MissionCanyon reservoir was made to determine the trappingconditions (DeMis, 1987, 1992). Water salinities,oilwater contacts, and net pay distributions werededuced from well logs and completion records. Thereservoir extent and water salinities at Knutson field

have been published (Bogle and Hansen, 1987). Allof these studies provide evidence of hydrodynamicconditions and effects on oil accumulation.

FORMATION WATER SALINITIES

Formation water resistivities and equivalent NaClsalinities were determined from the interpretation of

fluid recoveries on drill-stem tests in selected wildcatwells throughout the area and supplemented by loginterpretation in some fields. Water resistivities rangefrom 0.05 ohm m (4000 ppm) on the southwest inKnutson field to less than 0.01 ohm m (>200,000 ppm)in the northeast (Figure 6). A prominent tongue ofbrackish to saline water extends into the Billings Nosefields from the southwest, and the pattern suggeststhat fresher waters have intruded the Mission Canyonby hydrodynamic flow from the outcrops beyond themap area to the south and southwest. Two othertongues of less saline water occur to the northwestand southeast, but these are not well defined.

The interpretation of well logs in the study areassupports the regional salinity map. For example,

along the Billings Nose, the salinities of formationwaters range from brackish to highly saline fromsouth to north across the fields. This range is illustrat-ed by graphs of Rt() for two wells (Figure 5). A wellin T-R field at the south end of the area has an appar-ent water-saturated resistivity (Ro) of 9 ohm m at 10%porosity. Extrapolation of this value to 100% porositygives an apparent water resistivity (Rw) of 0.09 ohmm at formation temperature (Figure 5A) and an


Figure 5Interpretation of true resistivity as a function of porosity in the Mission Canyon reservoir, Billings Nosearea. (A) Updip well in T-R field showing extrapolation of 100% water saturation line to water resistivity of 0.09ohm m. (B) Downdip well in Big Stick field showing extrapolation of 100% water saturation line to water resistivityof 0.018 ohm m. In both wells, the validity of the interpretation is confirmed by initial production from perforatedintervals and their apparent water saturations. From interpretation by Mitsdarffer (1985).

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equivalent NaCl salinity of 22,000 ppm. The reliabilityof this interpretation is confirmed by a measuredwater salinity of 15,000 ppm NaCl recovered on drill-stem testing in an adjacent well and by the initialpotential of the section. According to the graph, theperforated intervals have water saturations (S

w) that

range from about 45 to 55%, indicating that both oiland water could be produced from the zone. The ini-tial production of 506 bbl/day of oil and 421 bbl/dayof water confirms that the graph correctly predictssaturations and, furthermore, that the water-saturatedresistivities are essentially correct.

A well in the north part of the area in Big Stickfield has an apparent water-saturated resistivity (Ro)of 1.8 ohm m at 10% porosity (Figure 5B). Extrapola-tion of this value to 100% porosity gives an apparentwater resistivity of 0.018 ohm m at formation tem-perature and a salinity of 160,000 ppm NaCl. Theperforated intervals have indicated water saturations

in the range of 30 to 40%, which suggest the produc-tion of water-free oil. The initial potential of 2500bbl/day of oil with only a small amount of waterconfirms the predicted saturations as well as the esti-mate of formation water salinity. Waters of equallyhigh salinities were recovered in adjacent wells ondrill-stem tests of the section.

The water salinity map (Figure 6) representschanges in the Mohall and Glenburn intervals below

the producing horizons because these intervals commonly 100% water saturated. Similar patternssalinity change, however, are represented by salties of waters produced with oil in several fie(Bogle and Hansen, 1987; DeMis, 1987; Breig, 198Outside the fields, the map represents only a bestimate of water salinities from drill-stem test receries. Nevertheless, the changes depict a major insion of less saline waters over a broad area.

POTENTIOMETRIC SURFACE

A regional potentiometric surface for the formawater was established from measured reservoir psures (Figure 7). The calculation of hydraulic heaccounts for the salinity differences in the formatwater. The flow of formation water is normal to potentiometric contours, northward in the south p

of the area and eastward in the north. The patternflow generally conforms to the change in water saty (Figure 6) and confirms the flow of brackish wafrom the south and west. Two areas of low potenoccur as reentrants in the regional pattern and inclthe Elkhorn Ranch field and the Knutson-BillinNose fields. These lows represent traps or volumerock in which there is a local minimum potentialfurther movement of oil (Hubbert, 1953). Little K

Berg et al.

Figure 6Salinity of formation water in the Mohall andGlenburn intervals of the Mission Canyon formation inthe Billings Nose area. Contours in parts per thousand

() NaCl; contour interval is variable. Map was pre-pared from reported fluid recoveries on drill-stem testsand does not necessarily represent detailed salinitychanges in local field areas. Note the occurrence of a

brackish water tongue invading the Mission Canyon for-mation from the southwest.

Figure 7Freshwater potentiometric surface in the Msion Canyon formation, Billings Nose area. The pottiometric gradient is toward the east and implies a g

erally eastward flow of formation waters. Contointerval is 100 ft. Circles denote control wells for map. Ground elevations in the area range from 716850 m (2350 to 2800 ft).

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field is also associated with a potentiometric low, butthere were too few early drill-stem tests in that area todetermine original pressures and define the extent ofthe potentiometric low.

Potentiometric gradients outside the producingareas appear to be about 6 m/km (30 ft/mi). Withinthe lows, however, the gradients are small and maybe only about 2 m/km (10 ft/mi).

Hydraulic heads for the area were calculated usinga correction for the changes in salinity across the

area. If a constant density of formation water wereused, the heads would not correctly represent thepotentiometric surface. For example, assuming afreshwater gradient of 9.8 kPa/m (0.433 psi/ft), thecalculated heads would be too high in the area ofsaline formation waters. The corrected heads werecalculated as follows.

In the Billings Nose area, the change in formationwaters from weakly brackish to highly saline takes

place in a depth interval of approximately 61 m (200ft) from an elevation of 2073 to 2134 m (6800 to7000 ft). Pressures measured in the brackish zoneare due to a column of low-salinity water above thelevel of measurement. In the saline zone, however,the measured pressures include the additionalweight of saline water, assuming an abrupt salinitychange at 2073 m (6800 ft). For example, a 61-m(200-ft) column of saline water would exert a hydro-static pressure of (200 ft 0.465 psi/ft) = 93 psi. If a

freshwater gradient were assumed, the pressurewould be (200 ft 0.433 psi/ft) = 87 psi. Therefore,the pressure difference would be 6 psi, or about 15ft of head. The pressure difference is less than theprecision of pressure buildup measurements and isnegligibly small as compared to the total pressure.

We conclude that the corrected heads are a satis-factory approximation in the transition zone frombrackish to highly saline waters for regional mapping.


Figure 8Maps of the Billings Nose fields (compiled by Mitsdarffer, 1985). (A) Structure on top of the MissionCanyon formation showing producing area along structural noses and connected across shallow syncline. Contourinterval is 15 m (50 ft). (B) Thickness of net pay in the A zone showing porosity pinch-out along a northeasterntrend. Contour interval is variable from 1.5 to 3.0 m (5 to 10 ft). Oil production to the southeast at Whiskey Joe and

Franks Creek is from the B zone and exists without stratigraphic or structural closure.

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In areas of low potentiometric gradients, however, themeasured pressures may not be sufficiently accurateto establish the true gradients.

FIELD EXAMPLES

The potentiometric gradient across the areaimplies that the oil accumulations are affected by theflow of formation waters. These effects have been

documented by detailed mapping of the oil distribu-tion in several fields.

Billings Nose Fields

The structure is dominated by two distinct nosesin a regional dip of about 5 m/km (25 ft/mi) to thenorth-northeast (Figure 8A). The T-R, Big Stick, and

Four Eyes fields occur along the western nose, athe Franks Creek, Whiskey Joe, and Tree Top fieare along the eastern nose. Oil production extealong both noses, and no significant structural csures can be mapped. In the central part of the aroil production extends across the shallow synclbetween Big Stick and Tree Top. The total vertheight of the oil column is 46 m (150 ft) from T-Rthe south to Tree Top on the north.

The principal producing zone is the lower Sh

wood (A zone), which has an average net thicknof about 3 m (10 ft) and a maximum net thicknes6.1 m (20 ft) (Figure 8B). The porous zone is abruly terminated by a facies change to evaporites aloa northeast trend that crosses the area from T-RTree Top. Production southeast of this pinch-oufrom a thin, porous section of the underlying lowmost Sherwood (B zone).

The initial flow rates of wells completed in th

Berg et al.

Figure 9Maps of the Billings Nose fields (compiled by Mitsdarffer, 1985). (A) Initial potentials of wells complein the A zone showing higher potentials in the north and lower potentials and increasing water cuts to the sou(B) Elevations of the oilwater contact showing an average gradient of 5 m/km (25 ft/mi) to the northeast in central part of the field. Oilwater contacts based on level of 100% water saturation estimated from cross plots

Rt() (see Figure 5) and confirmed by drill-stem test recoveries.

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zone show that the higher potentials are displaced in adowndip direction (Figure 9A). Completions of 1000bbl/day of oil or more are concentrated in the BigStick field, whereas areas updip and downdip showdecreased potentials as well as increasing amounts ofproduced water. Low potentials with large water cutsare common in the T-R field to the southwest.

The apparent oilwater contact for the area (Figure9B) was established by graphs of true resistivity as afunction of porosity (Figure 5), and the highest zone

of 100% water saturation was taken as the oilwatercontact. This interpretation of the contact was con-firmed by fluid recoveries on drill-stem tests or by ini-tial fluid production. The contact has a maximum gra-dient of 4.8 m/km (25 ft/mi) to the northeast acrossBig Stick and flattens to the southwest and northeast.

Formation water resistivities were determined bythe same method of well log interpretation (Figure5). The water resistivities range from 0.08 ohm m on

the south at T-R field to 0.01 ohm m on the north(Figure 10A). These resistivities are equivalent to25,000 ppm and 200,000 ppm NaCl, respectively, atan average formation temperature of 115C (240F).The northward increase in salinity reflects the inva-sion of meteoric water from southwest to northeastacross the area, diluting the normally highly salinewaters of the MohallGlenburn interval (C zone).

The resistivities represent waters in the C zoneaquifer that immediately underlies the oil-productive

A and B zones, because the highest water saturationsoccur in the C zone. However, nearly the same pat-tern of resistivities is reflected in the salinity of watersproduced with the oil (Breig, 1988). Apparently, thedilute formation waters are also invading the reservoirzones despite the low relative permeability to water.

The potentiometric surface for the reservoir zonewas attempted from drill-stem test pressures using acorrected gradient to account for salinity change


Figure 10Formation water resistivities and potentiometric surface in the Billings Nose fields. (A) Water resistivi-ties in the Mission Canyon C zone estimated from Rt() plots (Figure 5) and confirmed by drill-stem test recoveries.Contours in ohm m; contour interval variable. Map compiled by Mitsdarffer (1985). (B) Potentiometric surfaceshowing apparent gradient generally to the east. Heads were calculated using a freshwater gradient of 9.8 kPa/m

(0.433 psi/ft) and corrected for increasingly saline waters downdip.

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(Figure 10B). Only selected well tests were used,those with the highest local pressures and that hadthe most reliable extrapolations of pressure buildup.This selection eliminated tests that showed draw-down of pressures by nearby production.

The potentiometric map suggests that flow of for-mation water is generally eastward, normal to theisopotential contours. In the producing area, the mapis contoured to ensure that the reservoir occupies alow-potential volume of rock that is outlined by the990-m (3250-ft) contour. This low-potential area con-forms to the flow pattern inferred from the tilt of theoilwater contact (Figure 9B) and from the salinity

change toward the northeast (Figure 10A). Further-more, the limit of the A zone reservoir is assumed tobe a no-flow boundary. Beyond the A zone limit, thepotentiometric surface represents the B zone, and thesurface continues to dip toward the southeast.

A small area of potentiometric closure is shown atT-R field in the southwest part of the map (Figure10B). This low-potential area probably results fromdrawdown of pressures by oil production from earlier

wells to the northeast. The low does not represenlocal sink because pressures and heads are greateporous zones above and below the Mission Canyo

The pressure control is too sparse, and the errinherent in drill-stem test measurements too largedetermine accurately the hydraulic gradient acrthe oil accumulations. It can be concluded only tthe flow of formation waters is generally eastwacross the Billings Nose fields and that flow is dived locally to the northeast along the porosity limithe A zone. It is likely that the gradient to the noeast is only about 2 m/km (10 ft/mi). To establismore accurate gradient, bottom hole pressures

early wells should be used for head calculations.

Elkhorn Ranch Field

The structure at Elkhorn Ranch is a single, bronose that plunges northward (Figure 11A). A poble small closure of 8 m (25 ft) or less occurs at southern limit of the field, and the eastern flank

Berg et al.

Figure 11Maps of the Elkhorn Ranch field in the northwestern part of the Billings Nose area; location of fielshown in Figure 2. Maps adapted in part from DeMis (1992); well symbols are the same as in Figure 9. (A) Structon top of the Mission Canyon formation showing displacement of the oil accumulation to the northeast. (B) Eletion of the oilwater contact showing a gradient to the northeast at about 5 m/km (25 ft/mi). Map is drawn on

base of 100% oil production. Contour interval is 7.6 m (25 ft).

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the nose has local dips that are as much as 19 m/km(100 ft/mi) to the east. Judging from the extent of theoil-productive area, the oil accumulation is displacedin the direction of plunge. The total vertical height ofthe oil column is 38 m (125 ft).

The oilwater contact has an apparent tilt towardthe east-northeast at a rate of 5 m/km (25 ft/mi) (Fig-ure 11B). The map is based on well completionrecords, and the oilwater contact is defined as thelowest level of 100% oil production, or the top of thetransition zone. Therefore, the map assumes a singleoil column, whereas there are multiple, thin produc-ing zones, each of which may have separate

oilwater contacts. In any case, the aggregate oil col-umn is clearly displaced generally downdip in anortheastward direction.

Two producing zones were mapped using porosi-ty cutoffs of 12% in the Sherwood zone and 8% inthe Bluell zone (DeMis, 1987). The lowermost zone,lower Sherwood, has an average net thickness ofonly 2 m (6 ft), but the porosity extends updip fromthe field area and to the east where only water pro-

duction was encountered (Figure 12A). Therefore,there appears to be no present structural or strati-graphic closure that limits the oil production. Rather,the accumulation owes its location entirely to hydro-dynamic tilt and can be thought of as a simplehydrodynamic trap.

The overlying Bluell zone has an average netthickness of only 1.2 m (4 ft) (Figure 12B), and it hasa distinct trend to the northeast. Oil production islimited by the line of zero thickness, which alsotrends northeast. In this case, the original trap mayhave been stratigraphic and controlled by the limitsof porosity, but the existing wells show that under

hydrostatic conditions, this zone would lose its oil bymigration updip to the southwest. The oil accumula-tion has been displaced to the northeast along thepinch-out. Therefore, the Bluell oil accumulation is ina combination stratigraphichydrodynamic trap.

The inferred flow of formation water is supportedby the change in formation water resistivities acrossthe producing area (DeMis, 1992). The apparentresistivities range from 0.05 ohm m on the southwest


Figure 12Maps of net pay at Elkhorn Ranch field (adapted from DeMis (1987). Contour interval is variable,0.61.2 m (24 ft). (A) Thickness of net pay in the lower Sherwood zone based on a porosity cutoff of 12% andshowing producing area (shaded) that does not depend on structural or stratigraphic closure. (B). Thickness of netpay in the Bluell zone based on a porosity cutoff of 8% and showing producing area (shaded) controlled in part byloss of porosity along a northeastern trend.

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to 0.02 ohm m on the northeast, which correspondto salinities of 130,000 and 180,000 ppm NaCl,respectively, at formation temperature. The magni-tude and direction of change strongly suggest thatthe flow of formation water is toward the northeastand is responsible for the tilt of the oilwater contactin the same direction.

Other Fields

Indirect evidence of hydrodynamic flow is found inother fields in the Billings Nose area. One example isthe Knutson field in the southwestern part of the area(Figure 3). The field is located on a minor nose, andno structural closure is present (Bogle and Hansen,1987). The distribution of wells indicates that the oilaccumulation is displaced downdip with a gradient oftilt of about 3 m/km (15 ft/mi). The main producingzone appears to be equivalent to the lower Sherwood(A zone) at T-R and Big Stick fields. Oil production islimited on the east by a pinch-out of the porous zone,which trends to the northeast (Figure 3).

The effect of hydrodynamic flow is based solely onthe apparent displacement of the producing areadowndip and in the direction of the local potentio-metric gradient, which appears to be about 6 m/km(20 ft/mi) to the northeast and parallel to the porositypinch-out (Figure 7). The direction of flow is support-ed by measured resistivities of produced water thatrange from 1.5 ohm m on the southwest to 0.5 ohm mon the northeast. These values correspond to salinitiesof 4000 and 13,000 ppm NaCl, respectively, at forma-tion temperature. The low salinities are attributed tothe location of the field to the southwest (Figure 6)where dilution by meteoric waters is greatest.

A second example is the Little Knife field, part ofwhich is included in the Billings Nose study area (Fig-ure 3). Based on structure maps, the producing areaappears to be displaced eastward on a large nose(Lindsay and Kendall, 1985), which suggests a hydro-dynamic effect. However, there are no publishedmaps that document the oilwater contacts in the payzones, and original pressure measurements from drill-stem tests are too few to establish local potentiometricor salinity gradients. The field lies in a high watersalinity area, and if tilted oilwater contacts are pre-sent, the gradients can be expected to be less thanthose at either the Billings Nose or Elkhorn Ranch

fields because of the higher oilwater density contrast.

HYDRODYNAMIC EFFECTS

The field data clearly show that (1) the oil accu-mulations are displaced in a downdip direction; (2)there is a great range in formation water salinities,increasing downdip; and (3) the flow of formation

water is generally toward the east, across the strtural dip. These facts strongly suggest that oil been displaced by hydrodynamic flow.

Eastward flow of formation water is at an obliqangle to the pinch-out of the major producing zonand the oil accumulations are displaced to the noeast along the pinch-outs. This relationship suggethat the flow of formation water is locally diver

along the pinch-outs to a northeastward directionflow and at an angle to the regional flow. The pottiometric gradients are low and cannot be accuratdepicted by the distribution of heads. For exampin the Billings Nose, there is little apparent changehead along the pinch-out of the lower Sherwoodzone (Figure 10B). Therefore, the local potentiomric gradients along the oil accumulations couldon the order of only 2 m/km (10 ft/mi). Even tlow gradient would have a significant effect on oi

According to Hubbert (1953), the oilwater depends on the hydraulic gradient multiplied byamplification factor that is proportional to the qutity of water density divided by the density diffence between the oil and water. For reservoir contions in the Billings Nose area, the densitybrackish water is 1.0 g/cm3, the density of salwater with an average of 100,000 ppm NaCl is 1g/cm3, and the density of the oil is 0.625 g/cThus, the amplification factor is 2.67 in reservowith brackish water and 2.54 in reservoirs wsaline water. If the hydraulic gradient is 2 m/km ft/mi), the oilwater tilt should be about 5.3 m/(28 ft/mi), which is the same as observed tilts baon field studies. These tilts, however, are appromately equal to the regional structural dip, whindicates that oil can not be trapped on regional but will be moved in the direction of flow. Onlslight increase in dip locally is required to formtrap, as in the Lower Sherwood zone at ElkhRanch (Figure 12A).

In some areas to the west, the regional hydraugradients appear to be as high as 5 m/km (25 ft/(see Figure 7). Then the tilts of oilwater contacould be about 12 m/km (64 ft/mi), much greathan the average structural dip. It can be concludthat oil in such areas has been flushed unless lostructural dip exceeds the tilt.

In the Billings Nose area, there are three typestraps that can contain oil: stratigraphic, stratigraichydrodynamic, and hydrodynamic (Figure 1

These types are named according to the princimechanism that controls closure on the oil accumlation.

The simple stratigraphic trap would be formwhere the northeast trend of a capillary pressbarrier turns locally toward the northwest and pvents oil from being flushed downdip (Figure 13This type of trap is suspected in limited areas, has not yet been identified as a major trap. F

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example, the one-well accumulation in the Bluellzone northeast of Elkhorn Ranch appears to be ofthis type (Figure 11B; Sec. 13, T144N, R101W). Inaddition, two wells in the south part of the Knutsonfield (Bogle and Hansen, 1987) are located in a smallreentrant along the northeast trend of the porositylimit. More of these simple stratigraphic traps can beexpected in the area.

In the stratigraphichydrodynamic trap, the oil isdisplaced downdip along the capillary pressure bar-rier by water flow (Figure 13B). This type of trap isreadily identified in the area (see Figures 8B, 9A). Inthe simple hydrodynamic trap, the oil is displaced byflow and its location is not associated with a capil-lary pressure barrier but only with a slight increasein structural dip in the direction of flow (Figure13C). This type was first recognized in the ElkhornRanch field (DeMis, 1987) (see Figure 12A) and alsooccurs in the Big Stick and Four Eyes fields (Figure8A). Structure plays a minor role in all of these typesof traps, but there are no known structural traps in

which the present accumulation is determined solelyby structure.

MIGRATION HISTORY

The Mississippian Bakken shale is the most likelysource rock for Mission Canyon oil (Dow, 1974;Williams, 1974; Meissner, 1984; Webster, 1984), and

the Billings Nose area is near the southern boundaryof mature Bakken source rock. The highly organicshales lie about 301 m (1000 ft) below the reservoirsand are separated from them by the dense, micriticlimestone of the Lodgepole formation. Oil generationbegan in the central basin about 80 Ma, according tothe burial history (Webster, 1984), and reached peakgeneration in the Billings Nose area during the lateEocene (40 Ma) (Dembecki and Pirkle, 1985).

Migration of the Bakken oil to overlying reservoirstook place through fractures in the Lodgepole for-mation (Figure 14A). Extensive fracturing occurs in atrend that extends through the Billings Nose area tothe northwest where oil production from fracturedMission Canyon Limestone is found in the Mondakfield (Parker and Hess, 1980). The origin of fractur-ing is believed to be from solution collapse over the

edge of the deeper Devonian Elk Point evaporites(Parker, 1967; Kearns and Traut, 1979). Fracturesoccur in the Mission Canyon at Little Knife field andare believed to have formed before migration (Narrand Burruss, 1984). Fractures that assist productionare suspected in other fields (Petty, 1988). All ofthese indications of fractures tend to support theidea of fracture migration.

After oil migration upward to the Mission Canyon,


Figure 13Diagrams of Mission Canyon traps in theBillings Nose area. (A) Stratigraphic trap with downdippinch-out. (B) Hydrodynamicstratigraphic trap in

which oil is displaced along a porosity pinch-out. (C)

Simple hydrodynamic trap with oil displaced downdipagainst a slight increase in dip.

Figure 14Sequence of oil migration and accumulation

in the Billings Nose fields illustrated by diagrammaticcross sections. (A) Oil migration upward along fracturesfrom the underlying Bakken shale source under nearlystatic conditions and oil accumulation in low-relief, struc-tural noses. (B) Brackish water tongue reached the areaduring the Pliocene, increasing the potentiometric gradi-ent and tilting oil accumulations down structural dip.

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there were at least four periods during which hydro-dynamic flow could have affected further migrationand accumulation: Laramide, Pliocene, Pleistocene,and Holocene. The present structure of the basinwas established during the Laramide orogeny fromLate Cretaceous (80 Ma) to early Eocene (52 Ma)when uplift of mountains to the south and westexposed Paleozoic aquifers to recharge anddowndip flow. Hydrodynamic conditions at this timecould have assisted oil migration. However, theuplifts were reduced by erosion to near sea levelduring the Eocene, and flow was similarly reduced.At peak generation in the late Eocene (40 Ma),

hydrodynamic gradients were probably low andaquifer conditions were essentially static (Figure14A).

Regional uplift of the Rocky Mountains and GreatPlains to their present elevations took place duringthe late Pliocene (2 Ma) (Love et al., 1963). At thistime, the entire stratigraphic section was exposedagain around the margins of the Black Hills and themountain ranges to the west and southwest. The Mis-

sion Canyon and other aquifers were rechargedmeteoric water at high elevations, and hydrodynaflow across the area was initiated (Downey, 198Freshwater from the outcrop invaded the deep ssurface and diluted the existing brines. The oil pottiometric surface was locally tilted and oil accumtions were displaced downdip (Figure 14B).

Pleistocene glaciation occurred over the northepart of the basin and provided a temporary sourcerecharge over what is now the discharge area. Simlations suggest that aquifer flow may now be rejusting to the earlier pattern established during Pliocene (Downey et al., 1987).

The present hydraulic gradients are gentle, the oil potential gradients are nearly equal to, orsome places greater than, the regional structural dThis relationship means that the oil accumulatioare not in equilibrium with the present hydrodynic regime but instead are moving in a downdirection, giving further support to the idea treadjustment of oil accumulations is now takplace.

Berg et al.

Figure 15Hypothetical Mission Canyon prospect in the Billings Nose area. (A) Structure on top of Mission Canporosity confirmed by discovery (well 1), which is offset by dry holes (wells 2 and 3). Well 2 has a show of oil in a column of about 2 m (7 ft). (B) Possible reservoir limits (dotted line) defined by reduced porosity to the southeast 12%) and tilt of oilwater contact to the northeast at 5.7 m/km (30 ft/mi). Arrows point to intersections of the planthe oilwater contact with structure contours. Proposed location is predicted to encounter about 5 m (15 ft) of pay

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APPLICATIONS

The Mission Canyon formation has been exten-sively drilled in the Billings Nose area, but the signif-icant oil reserves and the dominance of hydrody-namic effects indicate that abundant prospects mayhave been overlooked by traditional mapping tech-niques. Previous exploration has relied largely on

locating structural closures and on stratigraphic map-ping to define porosity limits using cutoffs of 6 to 8%porosity. However, some zones have unusually highcutoffs of 12 to 15% for water-free oil production(DeMis, 1987; Petty, 1988). Future success in thearea depends on understanding the hydrodynamiceffects as well as the capillary properties of theporous zones.

Predicting the occurrence of oil will be least haz-ardous for those accumulations related to strati-graphic changes. A hypothetical example is a one-well field, typical of several in the area (Figure 15A).The discovery, well 1, found 3.6 m (12 ft) of oil pro-ductive section above water and was offset to thewest and south by dry holes, wells 2 and 3, whichfound the pay section to be porous but water pro-ductive. No reasonable explanation for stratigraphictrapping can be found to explain the dry holes usinglow porosity cutoffs (for example, see Longman,1981). The pay section in well 3, however, had anaverage porosity of less than the cutoff value of 12%for water-free production (DeMis, 1987). Thus, acapillary pressure barrier is suspected that trendsnortheast, parallel to the regional pinch-outs (seeFigure 3). Furthermore, a show of oil in well 2 sug-gests that the pay section there might be on theoilwater contact.

It can be assumed that the oilwater contact is tilt-ed at the rate of 5.7 m/km (30 ft/mi) to the northeast,similar to tilts observed in nearby fields. The plane ofthe oilwater contact is overlain on the structuralmap, and its intersections with structural contoursdefines the limits of the reservoir (Figure 15B).According to this construction, a location northeast ofthe discovery well and downdip should encounterabout the same thickness of reservoir section.

In this example (Figure 15), the reservoir is limit-ed on the northeast by increased structural dip toabout 15 m/km (80 ft/mi), which is significantlygreater than the tilt of the oilwater contact. In theabsence of greater structural dip, the oil accumula-

tion could be expected to extend farther north andnortheast, similar to the displacements of producibleoil in the nearby fields. Where evidence for a capil-lary pressure barrier is missing, a favorable offset toa discovery well is still in a northeastward direction,parallel to observed tilts. Essential to any interpreta-tion is knowledge of the reservoir structure, whichwill determine the extent and thickness of the accu-mulation.

CONCLUSIONS

Oil accumulations in the Billings Nose area aretilted to the northeast by the flow of formationwaters. The gradients of tilt are about 5 m/km (25ft/mi), approximately the same as the regional struc-tural gradient. This relationship means that oil mightbe flushed downdip and that some accumulations

are unstable under the present conditions of flow.Small dip changes in local areas would increase ordecrease the probability of trapping.

It is likely that the major oil accumulations wereoriginally in stratigraphic traps along the northeasttrend of the porosity pinch-outs and that the accu-mulations were later modified by hydrodynamicflow. Some accumulations in the area are not con-trolled by stratigraphic change and appear to owetheir locations entirely to flow. The prediction oftraps in exploration is complicated by the fact thatthe present oil accumulations are not in equilibriumwith the flow of formation water. Wildcat drilling onsmall structural closures assuming hydrostatic condi-tions, however, is not a correct exploration method.Displaced oil accumulations can occur along porosi-ty pinch-outs or as isolated pools without closure.Therefore, exploration can be guided by a carefulevaluation of oil shows, by detailed mapping ofreservoir properties of thin porous zones, and by awillingness to drill downdip from indications of oilin water-wet zones.

Effects of hydrodynamic flow on oil accumula-tions can be expected in other basins where aquifersare charged by meteoric water through outcrops athigh elevations. Flow of formation water can bedetected with relatively few pressure measurementsin an early stage of exploration. Where hydraulicgradients are low, as in the Billings Nose area, flowcan be suspected whenever there are distinctchanges in the salinity of formation water. Then theeffect of flow can be anticipated in exploratorydrilling as well as in field development.

REFERENCES CITED

Altschuld, N., and S. D. Kerr, Jr., 1982, Mission Canyon and Duperowreservoirs of the Billings Nose, Billings County, North Dakota, inJ.E. Christopher and J. Kaldi, eds., Fourth International WillistonBasin Symposium, Regina, Saskatchewan, p. 103112.

Berg, R. R., 1975, Capillary pressures in stratigraphic traps: AAPGBulletin, v. 59, p. 939956.

Bogle, R. W., and W. B. Hansen, 1987, Knutson field and its relation-ship to the Mission Canyon oil play, south-central Williston basin,inC. G. Carlson and J. E. Christopher, eds., Fifth International

Williston Basin Symposium, Saskatchewan Geological SocietySpecial Publication 9, p. 242252.

Breig, J. J., 1988, Mississippian Mission Canyon reservoirs of the BillingsNose, Billings County, North Dakota, inS. M. Goolsby and M. W.Longman, eds., Occurrence and petrophysical properties of carbon-ate reservoirs in the Rocky Mountain Region: Denver, Colorado,Rocky Mountain Association of Geologists, p. 357370.


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Carlson, C. G., and J. A. LeFever, 1987, The Madison, a nomenclaturereview with a look to the future, inC. G. Carlson and J. E. Christo-pher, eds., Fifth International Williston Basin Symposium:Saskatchewan Geological Society Special Publication 9, p. 7782.

Dembecki, H., Jr., and F. L. Pirkle, 1985, Regional source rock map-ping using a source potential rating index: AAPG Bulletin, v. 69,p. 567581.

DeMis, W. D., 1987, Hydrodynamic trapping in Mission Canyonreservoirs, Elkhorn Ranch field, North Dakota, inC. G. Carlsonand J. E. Christopher, eds., Fifth International Williston Basin

Symposium: Saskatchewan Geological Society Special Publication9, p. 217225.

DeMis, W. D., 1990, Depositional facies, textural characteristics, andreservoir properties of dolomites in FrobisherAlida interval insouthwest North Dakota: Discussion: AAPG Bulletin,

v. 74, p. 564565.DeMis, W. D., 1992, Elkhorn Ranch fieldU.S.A., Williston Basin,

North Dakota, inN. H. Foster and E. A. Beaumont, eds., Strati-graphic traps III: AAPG Treatise Atlas of Oil and Gas Fields,p. 369388.

Dow, W. G., 1974, Application of oil correlation and source-rock datato exploration in Williston basin: AAPG Bulletin, v. 58,p. 12531262.

Downey, J. S., 1984, Geology and hydrology of the Madison Lime-stone and associated rocks in parts of Montana, Nebraska, NorthDakota, South Dakota, and Wyoming: U.S.G.S. Professional Paper1273-G, 152 p.

Downey, J. S., J. F. Busby, and G. A. Dinwiddie, 1987, Regionalaquifers and petroleum in the Williston basin region of UnitedStates, inM. W. Longman, ed., Williston basin: anatomy of a cra-tonic oil province: Denver, Colorado, Rocky Mountain Associa-tion of Geologists, p. 299312.

Hansen, A. R., 1972, The Williston basin, inW. W. Mallory, ed., Geo-logic atlas of the Rocky Mountain region: Denver, Colorado,Rocky Mountain Association of Geologists, p. 265269.

Horner, D. R., 1951, Pressure buildup in wells, in Third WorldPetroleum Congress Proceedings Section II: Leiden, E. J. Brill, p.503521.

Hubbert, M. K., 1953, Entrapment of petroleum under hydrodynamicconditions: AAPG Bulletin, v. 37, p. 19542026.

Kearns, J. R., and J. D. Traut, 1979, Mississippian discoveries revivethe Williston basin: World Oil, May, p. 5257.

Kupecz, J. A., 1984, Depositional environments, diagenetic history,and petroleum entrapment in the Mississippian FrobisherAlidainterval, Billings anticline, North Dakota: Colorado School ofMines Quarterly, v. 79, no. 3, 53 p.

Lindsay, R. F., 1987, Carbonate and evaporite facies, dolomitization,and reservoir distribution of the Mission Canyon formation, LittleKnife field, North Dakota, inM. W. Longman, ed., Williston basin,anatomy of a cratonic oil province: Denver, Colorado, RockyMountain Association of Geologists, p. 355383.

Lindsay, R. F., 1988, Mission Canyon formation reservoir characteris-tics in North Dakota, inS. M. Goolsby and M. W. Longman, eds.,Occurrence and petrophysical properties of carbonate reservoirsin the Rocky Mountain Region: Denver, Colorado, Rocky Moun-

tain Association of Geologists, p. 317346.Lindsay, R. F., and C. G. St. C. Kendall, 1985, Depositional facies,

genesis, and reservoir character of the Mississippian cyclic bonates in the Mission Canyon formation, Little Knife field, Wton basin, North Dakota, inP. O. Roehl and P. E. Choquette, Carbonate petroleum reservoirs: New York, Springer-Verla175190.

Lindsay, R. F., and M. S. Roth, 1982, Carbonate and evaporite facdiagenesis, and reservoir distribution of the Mission Canyon mation, Little Knife field, inJ. E. Christopher and J. Valdi, e

Fourth International Williston Basin Symposium, RegSaskatchewan, p. 153179.

Longman, M. W., 1981, Carbonate diagenesis as a control on stgraphic traps (with examples from the Williston basin): AAPGEducation Conference, Calgary, Canada, 159 p.

Love, J. D., P. O. McGrew, and H. D. Thomas, 1963, Relationshilatest Cretaceous and Tertiary deposition and deformation tand gas in Wyoming: AAPG Memoir 2, p. 196208.

Meissner, F. F., 1984, Petroleum geology of the Bakken FormaWilliston basin, North Dakota and Montana, inG. DemaisonR. J. Murris, eds., Petroleum geochemistry and basin evalua

AAPG Memoir 35, p. 159179.Mitsdarffer, A. R., 1985, Hydrodynamics of the Mission Canyon

mation in the Billings Nose area, North Dakota: Masters thTexas A&M University, College Station, Texas, 162 p.

Murray, G. H., 1959, Examples of hydrodynamics in the Willibasin at Poplar and North Tioga fields, inGeological Rec

AAPG Rocky Mountain Section: Denver, Colorado, PetrolInformation, p. 5559.

Narr, W., and R. C. Burruss, 1984, Origin of fractures in Little Kfield, North Dakota: AAPG Bulletin, v. 68, p. 10871100.

Parker, J. M., 1967, Salt solution and subsidence structures, WyomNorth Dakota, and Montana: AAPG Bulletin, v. 51, p. 192919

Parker, J. M., and P. D. Hess, 1980, The Mondak Mississippianfield, Williston basin, U.S.A.: Oil and Gas Journal, October 13210217.

Petty, D. M., 1988, Depositional facies, textural characteristics,reservoir properties of dolomites in FrobisherAlida intervasouthwest North Dakota: AAPG Bulletin, v. p. 12291253.

Pickett, G. R., 1966, A review of current techniques for determinaof water saturation from logs: Journal of Petroleum Technol

v. 18, p. 14251433.Webster, R. L., 1984, Petroleum source rocks and stratigraphy o

Bakken Formation in North Dakota, inJ. Woodward, F. F. Mner, and J. L. Clayton, eds., Hydrocarbon source rocks ofgreater Rocky Mountain region: Denver, Colorado, Rocky Mtain Association of Geologists, p. 5781.

Williams, J. A., 1974, Characterization of oil types in the Willibasin: AAPG Bulletin, v. 58, p. 12431252.

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Robert R. Berg

Robert R. Berg is a professor atTexas A&M University and holds theMichel T. Halbouty Chair in Geology.

His teaching experience of 27 years waspreceded by 16 years of practice as anexploration geologist and geophysicist.His research has concentrated on sand-stone reservoir characterization, capil-lary trapping, and hydrodynamiceffects on oil accumulations.

William D. DeMis

William D. DeMis is a geologist withMarathon Oil Company in Houston,Texas, and works in a worldwide basinanalysis team. He received an M.A.degree (1983) from the University ofTexas at Austin with an emphasis on

structure and tectonics. Prior to joiningMarathon in 1987, he worked the

Williston basin while employed byPennzoil Company. With Marathon, hisrecent work included exploration ofthe Smackover Formation of northLouisiana, and studies of basins in China and New Guinea.

Alan R. Mitsdarffer

Alan R. Mitsdarffer is a geologist forDupont Environmental RemediationServices and is currently working on

environmental projects ranging frominjection wells to RCRA investigations.He has a B.S. degree (1976) from theCollege of William and Mary and anM.S. degree (1985) from Texas A&MUniversity. His geologic experienceincludes minerals exploration (urani-um and coal), oil and gas develop-ment, and environmental work with an emphasis on hydro-geology.


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