Southern Ute Indian Reservation occurs throughout the coal seams underlying the Reservation. The coal, estimated to be in excess of 200 million tons of strippable coal, General Setting is high quality (10,000 BTUs per lb.) and with low sulfur content. U T A H C O L O R A D O The Southern Ute Indian Reservation is in southwestern Colorado Leasing of minerals and development agreements on the UTE MOUNTAIN UTE adjacent to the New Mexico border (Figs. SU-1 and -2). The reser- Southern Ute Indian Reservation are designed in accordance with the vation encompasses an area about 15 miles (24 km) wide by 72 miles Indian Mineral Development Act of 1982, and the rules and (116 km) long; total area is approximately 818,000 acres (331,000 regulations contained in 25 CFR, Part 225 (published in the Federal SOUTHERN UTE ha). Of the Indian land, 301,867 acres (122,256 ha) are tribally Register, March 30, 1994). The Tribe no longer performs lease owned and 4,966 acres (2,011 ha) are allotted lands; 277 acres (112 agreements under the old 1938 Act (since 1977). NAVAJO ha) are federally owned (U.S. Department of Commerce, 1974). The The 1982 Act provides increased flexibility to the Tribe and TAOS JICARILLA rest is either privately owned or National Forest Service Lands. The developer to tailor their agreements to the specific needs of each APACHE TAO Tribal land is fairly concentrated in two blocks; one in T 32-33 N, R party. It also allows the parties to draft agreements based on state-of- PICURIS

1-6 W, and the other in T 32 N, R 8-13 W and T 33 N, R 11 W. the-art oil and gas agreements used in industry rather than standard SAN JUAN Most of the allotted land is along or near Los Pinos River. This Bureau of Indian Affairs forms. The Act also contains sections which SANTA CLARA POJOAQUE NAMBE “checker-boarding” has had a profound effect on the development of set forth the responsibilities of BLM and MMS offices. The SAN ILDEFONSO HOPI the Southern Ute people. Unlike many tribes where they are isolated regulations contain a 21 point check list for matters which should be JEMEZ COCHITITESUQUE from outside influence, the Southern Utes have lived alongside non- considered, and if appropriate, included in any mineral agreement. SANTA DOMINGO Indians since the late 1800’s. Inquiries regarding new leasing should be directed to Robert ZIA SAN FELIPE The Tribal headquarters are located 1 mile north of the town of Santistevan, Director of Energy Resources, Red Willow Production NAVAJO I R LAGUNA SANTA ANA SANDIA Ignacio (Fig. SU-2). The city of Durango is located just outside the Company at: RAMAH north boundary of the Reservation, 24 miles northwest of Ignacio. ZUNI NAVAJO CANONCITO The population of the Tribe is currently 1,135 people. The Tribe Red Willow Production CO ACOMA ISLETA is growing rapidly with over half of the population under the age of Production Operating/Acquisition A R I Z O N A LAGUNA I R 25. Approximately 25 percent of the membership lives off the Reser- P.O. Box 737 N E W M E X I C O vation, mostly in larger metropolitan areas such as Denver, Albu- Tribal Annex bldg., 2nd Fl ALAMO NAVAJO querque, and Phoenix. There are 300 Tribal members in the local Ignacio, CO 81137 work force. In addition to Tribal Members, there are approximately Figure SU-1. Location of Southern Ute Indian Reservation with respect to other Indian Reservations (modified after Indian Land Areas, 1993). 30,000 people living in La Plata County. Tel: (970) 563-0140 Topography of the reservation is generally rugged. West of Ani- Fax: (970) 563-0398 mas River, the eastern flank of Mesa Verde is cut by numerous small 10900' canyons. Eastward the hills become more rounded and timber cov- 10830' 10800' 10730' 10700' 10630' ered. Elevations range from about 6,000 feet along La Plata River DOLORES CO AHUT SAN JUAN CO Needle near the southwest corner and along the San Juan River near Arboles, MONTEZUMA CO Stoner LA PLATA CO Mountains r ive to 8,551 feet at Piedra Peak (sec 24, T33N, R6W). Principal streams COLORADO McPhee R Dolores Resevoir on the Reservation are the San Juan, Piedra, Animas, Florida, and La 3730' Rands Gulf No. 1 Dolores Plata Rivers. The Navajo Reservoir, formed by Navajo Dam in New r J.A. Fulks x ve La Plata R i Mountains a Mexico, forms a significant body of water on the San Juan River and McElmo Canyon Cortez Animas City Pedr ARCHULETA CO CONEJOS CO the lower Piedra River in the eastern part of the reservation (Fig. SU- x Mountain Durango Pagosa Springs 2); water surface is at an elevation of about 6,100 feet. Bayfield erde Ignacio, with a population of 613 in 1970, is the largest town on SleepingMountain Ute Ignacio AN CO the reservation, and site of the Southern Ute Indian Agency. The ners Mesa v mor nearest large town is Durango, Colorado with a population of 10,333. SAN JU Four Corplatf Chromo It is about 5 miles north of the reservation (Fig. SU-2). Farmington, 3700' COLORADO SAN JUAN CO RIO ARRIBA CO NEW MEXICO New Mexico, with a population of 21,979 (1980), lies to the south Cedar Hill Dulce CHE CO

about 29 miles from the reservation boundary. AAP San J r Archuleta Arch uan k Monocline ve The climate is temperate with an annual average of 16 inches of Ri Navajo Reservoir a s Hogbac im rainfall. The growing season is about 109 frost free days between River An Figure SU-2. Index map showing Farmington May and September. the Southern Ute Indian The Southern Ute Indian Tribe is blessed with an abundance of Reservation and adjacent areas San Juan Basin N 0 10 20 valuable natural resources. A major source of revenue for the Tribe (modified after Condon, 1992). ARIZONA MILES is the production of oil and natural gas. Recent drilling and 3630' NEW MEXICO production activity has focused on coal-bed methane gas which

SOUTHERN UTE INDIAN RESERVATION Overview 1 COLORADO 112 111 110 109 108 107 Geology 41 EXPLANATION WYOMING WYOMING 41 The Southern Ute Indian Reservation is on the northern margin of UTAH COLORADO

Monocline or steep limb of fold 0 8 16 32 48 64 Miles

with direction of dip U TA UPLI the San Juan Basin, a large circular structural depression whose IN FT 0 8 16 32 48 64 80 96 Kilometers Crestal line of anticline, arch, uplift, up- SCALE

center is some 50 miles southeast of Durango (Fig. SU-3). The warp, or swell, with direction of plunge XA IA VERNAL L Troughal line of syncline, basin, or sag sedimentary layers that fill the San Juan Basin dip gently toward its with direction of plunge F

OLD center. Their outcrop pattern around the basin is a series of High-angle fault, with downthrown side UINTA ELB T

concentric bands, with the younger rocks toward the center and the 40 R MEEKER

E Thrust fault, with updrawn side R 10900' 10830' C 10800' 10730' 10700' 10630' IV 40

R older rocks toward the margin. Nearly all the rocks exposed at the A WHITE

Boundary of tectonic division S

A RIVER AHUT BASIN L surface on the Reservation are sedimentary rocks of Late Cretaceous G UPLIFT DOLORES CO 0 10 20 0 10 20

AHUT 30

U SAN JUAN CO Needle COLORADO Uplift IVR E PRICE O R MONTEZUMA CO D LA PLATA CO Mountains G SAYELLAVELTCAS G Stoner MILES KILOMETERS or Early Tertiary age (Fig. SU-4). PICEANCEO r AD CARBONERA CARBOND 6000 ve L i

OR COLORADO McPhee C L ores R La Plata Basin L l O 7000 8000 Do San Juan E SAG Resevoir Geologic Structure BASIN 3730' Mountains N EFA WSL ALE Dome EN E JUNCTION BENCH R Dolores La Plate The Southern Ute Indian Reservation is located in the northern part G Gulf No. 1 Rands

L r E Dome e 39 BASIN K McElmo Canyon J.A. Fulks x iv GREEN GR. U 39 4 10,000 R of the structural and sedimentary San Juan Basin. The present struc- RA RIVER JUNCTION P a N UNCOMPAHGRE UPLIFT L UTE Cortez Animas City dr CONEJOS CO I Pe ARCHULETA CO A F S P T x Mountain ture was largely shaped by Laramide (Late Cretaceous through Eo- TEA US ARADOX DOME 80009000 GUNNISON UPLIFT 6000 Durango LA SAL MONTROSE SA Pagosa Springs cene) and later tectonic activity. The area was also on the edge of CAPIT 7000 DOME Bayfield FOLD BEL O 5000 REEF MOAB D L e OL O GUNNISON 5000 FA R erd 4000 San Juan Sag the older Paleozoic Paradox Basin during deposition of the sedi- E S T ULT AND AN CO ROCKIES Mesa v ments of the Pennsylvanian Hermosa Group (Condon, S.M., 1992) H FOLD G ners 6000 E mor N R

Y E our Cor Figures SU-3, -4, and -5 show various structural elements in BELT SAN JU 2 5000

HIGH PLA HENR F platf 38 OP Chromo SA

L 38 Y DOMES 3700' 4000 COLORADO R southwestern Colorado and northwestern New Mexico. The struc- S NJUAN 2000 I V WILSON SAN SAN JUAN CO CIRCLE CLIFFS UPLIFT N E 3000 RIO ARRIBA CO NEW MEXICO B O DOME

A R San Juan Cedar Hill Dulce Y

ture contours in Figures SU-4 and -5 show effects of Laramide de- S A N ABAJO

IN W S A JICO

CHE CO P DOME 1000 JUAN A C

DOME AAP R G 1000 2000 formation. The San Juan Basin is flanked on the west by the Hog- E U NEEDLE IV E 4000 R T T r I LA PLATA DOME e COLORADO k Monocline -1000 H BLANDING DOME Riv Navajo Reservoir back Monocline and on the east by the Archuleta Arch. The mono- KAIPAROWITS 5000 s MEN DOME W CORTEZ AR gbac ima U CH R E An Archuleta Arch N BASIN River Ho U V 0 cline rim extends unbroken around the northern rim of the basin. DURANGO LET I Farmington O R 7000 BASIN A M UTE 8000

RA 6000 C O D O DOME OL AARIZON Superimposed on these major structures are several smaller ones: NAVAJO SOUTHERN UTE 37 DOME

A UTAH COLORADO ES

R 37

EC

T T N ARIZONA TFORM NEW MEXICO A San Juan Basin FOUR CORNERS C Chama PIUTEOLUET O the Barker anticline and Red Horse syncline in the southwest corner H C

KAI H SA G CARRIED PLA H

K FOLDS B O Basin

DOME N

A A A TYENDE UA M B

of the Reservation, the Ignacio anticline and H-D Hills syncline in I N J BA C KAIBITO FARMINGTON A S A NEW MEXICO S SADDLE 3630' L

Y RED ROCK N I F the central part, and several northwest-trending anticlines, synclines C BENCH F L SADDLE I S N SAN JUAN

E PRESTON BASIN and faults at the east end. U P D U L E P I F BENCH F L T I A structural bench, the Four Corners Platform, lies between the IF A T N BASIN Figure SU-5. Structure Contour map under and adjacent to the Southern Ute Indian Reservation. Structure C

E San Juan Basin and the Blanding Basin (Fig. SU-3). Upper Creta- BLACK MESA IUCIMIENTO UPLIFT 36 ARIZONA contours are drawn on the top of the Jurassic with a contour interval of 1000 feet. Major structural features are ceous to Tertiary laccolith intrusions of Ute dome and the La Plata NEW MEXICO 36 CAMERON labeled (modified after Condon, 1992). BENCH C BASIN H dome are evident (Fig. SU-3). The northern rim of the San Juan Ba- A COCONINO U GO

P H

SALIENT L

sin is defined by the uplift of the San Juan Dome. The Chama basin I FT S G WUPATKI BENCH GALLUP LOPE L T U I T and the San Juan sag are low structural features on the east and L E GALLUP ZUNI UPLIFT OR T BELT ULAF T BELT SAG PUERCO E D N

northeast sides, respectively, of the Archuleta arc (Fig. SU-5). G A T R FLAGSTAFF E The principal structures of economic significance are the Barker WINSLOW Figure SU-3. Tectonic divisions

35 ACOMA ALBUQUERQUED OLC 35 ORADO N

HOLBROOM A of the Colorado Plateau anticline, which produces gas from the Dakota and Hermosa Groups, SAG R MOGOLLON SLOPE RECU O (modified after Kelley, 1958). and the Ignacio anticline, which produces gas mainly from the G R PLIFT R I O V I E R L U

O Mesaverde and subordinately from several other formations from the I

R 112 111 110 Fruitland down to the Morrison (Fig. SU-4). 109 108 107

0 H-D Hillis Syncline Stinking Springs Anticline 400 5000 1000

1000 0

Florida r 4000 Sawmill 1500 er e er vRi Ti Red Mesa iv Canyon iv Mesa R R 1500 ta s nos H Ti uan Riv a a 500 i o Ne Pl 1 P g wton imn os b Anticline Ojo Alamo a L 1000 3000 ac Lewis Shale L A k 5000 San J Alluvium Sandstone 0 2000 M Mesaverde Group Structure Contour line 0 r on 0 Ig Ignacio e o Animas Fm 1 na v cl Klutter Mtn (Formation) drawn on base of Dakota ci i ine o Ignacio Anticline R Syncline Intrusive Mancos Shale Long Hollow ra d Ti Igneous rocks e Montezuma Anticline (extended) An l Kirtland Shale ticli ne P Dakota Sandstone Anticline, showing Ti Klutter Fruitland Fm ch San Juan Burro Canyon Fm plunge l Ti Pictured Cliffs Red Ho HOGBACK MONOCLINE u Mountain Fm rs G Bondad Morrison Fm e o Ti Sandstones Sy te y Wanakah Fm Syncline, showing nc o Mesa Mountains No Data lin o r Naciomiento e rA plunge N Coy Fm n High angle fault rmo 0 5 10 15 20 Miles De 15 Mc 00 Arboles 0 5 10 15 20 Kilometers Sa Juanita Archuleta n Ju an r Ti Mesa Riv e Ti

Figure SU-4. Generalized geologic and structure map of the Southern Ute Indian Reservation. Structure lines are drawn on the base of the Dakota Sandstone (modified after Anderson, 1995).

SOUTHERN UTE INDIAN RESERVATION Geology 2 COLORADO Stratigraphic Overview from the Lower Pennsylvanian Molas Formation. conglomerate and conglomeratic Pennsylvanian System fluvial-channel sandstone bodies. AGE FORMATION OR GROUP The following is a brief description of the stratigraphy under the SW The Molas Formation averages 60 feet thick on the Reservation. The The Late Cretaceous (Cenoma- NE Southern Ute Indian Reservation. The formations of oil and gas sig- nian) Dakota Sandstone lies either Molas Formation is composed of three members. They are the Coa- San Jose Formation nificance will be discussed in more detail in the “Play Summary bank Hill Member, the Middle Member, and the Upper Member. disconformably over the Burrow TERTIARY Overview”. Please refer to Figures SU-4, 5, 6, and 7. Nacimiento Formation They range from shale to conglomerate with some fossiliferous lime- Canyon Formation or unconforma- Older Paleozoic Systems stone. bly over the Morrison Formation Ojo Alamo Sandstone Fig. SU-6). It is exposed only in The oldest formation in the subsurface of the Southern Ute Indian The Hermosa Group conformably overlies the Molas Formation. Kirtland Shale (Farmington Sandstone Member) 1 Reservation is the Upper Cambrian Ignacio Quartzite which uncon- It ranges in thickness from 400 feet on the southeast side to thicker the valley of the San Juan River in formably overlies Precambrian metamorphic and igneous rocks (Fig. than 2,000 feet. The Hermosa Group consists of (from oldest to the northeast corner of the Reserva- Fruitland Formation 1 tion, but it underlies the entire Res- SU-6). The Ignacio is as thick as 150 feet in the northwest part of youngest) the Pinkerton Trail Formation, the salt-bearing Paradox Pictured Cliffs Sanstone 1 the Reservation and thins to about 30 feet in the Piedra River canyon ervation in the subsurface. It was Formation and the Honaker Trail Formation. The Paradox Formation Lewis Shale about 20 miles west of Pagosa Springs. It consists mainly of white, is composed of four main cycles of Desmoinian deposition. The cy- deposited in response to the initial reddish-brown, and light-brown conglomerate; feldspathic and cles are the Ismay, Desert Creek, Akah, and Barker Creek Stages. transgression of the upper Creta- Cliff House Sandstone 1 ceous epeiric sea. The Dakota verde Menefee Formation quartzoes sandstone; purple to green, burrowed, micaceous mudstone These are cyclic deposits of dolomite, limestone, and black, carbona- LATE and siltstone; and minor dolomite. The sandstone is very coarse to ceous shale. Porosity is 10% and more, which has made these cycles formed in a variety of environments MesaGroup Point Lookout Sandstone 1 fine grained. Bedding is thin to thick in tabular layers with small to and consists of a basal alluvial unit important as an oil and gas reservoir. Upper Mancos Shale 1 medium scale crossbeds. The lower Ignacio Quartzite was deposited that is overlain by deltaic, marginal- CRETACEOUS Pennsylvanian and Permian Systems subaerially in streams and on alluvial fans. The upper Ingacio marine, and marine rocks in differ- Gallup Ss. (Torrivio Mbr.) Tocito Ss. Lentil The Rico Formation averages about 200 feet thick on the Reserva- 1 1 Quartzite is a shallow-shelf assemblage of strata that was deposited ent parts of the region. Its thickness tion. It is composed of conglomeratic sandstone and arkose interbed- Lower Mancos Shale Greenhorn Limestone by the eastward transgressing sea. There is no production of hydro- on the Reservation is not known, ded with greenish-, reddish-, and brownish- gray shale and sandy fos- carbons or any other economic resource from the Ignacio in the vi- but nearby to the north it is 177-270 Dakota Sandstone siliferous limestone. The Rico Formation represents the transition cinity of the Reservation. feet thick. between the Cutler Group and the Hermosa Group. EARLY Burro Canyon Formation 1 The Cambrian-Devonian McCracken Sandstone Member and The Late Cretaceous Mancos Upper Member of the Elbert Formation unconformably overly the Lower Permian System Shale conformably overlies the Da- Morrison Formation (Todilto Limestone Member) Ignacio Quartzite and basement rocks (Fig. SU-6). The McCracken The Cutler Group ranges from 1,200 to 1,700 feet thick on the Reser- kota Sandstone and intertongues JURASSIC Wanakah Formation vation. It is mostly nonmarine red shale, siltstone, mudstone, sand- with the overlying Point Lookout Sandstone Member ranges from 0 -140 feet thick on the Reservation. Entrada Sandstone The McCracken consists of gray to brown sandstone, brown and gray stone, and conglomerate. It is composed of (from oldest to young- Sandstone. It underlies the entire dolomite, and greenish-gray shale. The dominant lithology is very est) the Halgaito Formation, Ceder Mesa Formation, Organ Rock Reservation and outcrops in the TRIASSIC Chinle Formation 1 Shale, and the De Chelley Sandstone (Fig. SU-6). fine to coarse grained sandstone. It is composed of shallow marine, northeast corner. It is mostly a dark De Chelley Sandstone gray marine shale and its maximum nearshore sediments that were deposited during a eustatic sea-level Triassic System Organ Rock Shale subsurface thickness on the Reser- Cutler rise in the Late Devonian. The Upper Member of the Elbert Forma- The Dolores Formation ranges in thickness from about 900-1,200 PERMIAN tion ranges from 150 to 250 feet thick on the Reservation. It con- feet on the west side of the Reservation. It is composed mostly of in- vation is about 2,400 feet. The low- Group Cedar Mesa Formation and related rocks sists of poorly exposed, thinly bedded, brownish-gray, sandy dolo- terbedded red to purplish-red, very fine to coarse grained sandstone, er part, about 500 feet thick, con- Halgaito Formation mite and sandstone; green to red shale; and minor anhydrite. The conglomerate, siltstone, and mudstone. The Dolores is interpreted to tains thin limy shale and limestone Rico Formation sediments were deposited in a shallow, tidal-flat environment. be fluvial-channel, flood plain, lacustrine, and eolian sand-sheet de- in the lower 150 feet. The upper The Devonian Ouray Limestone conformably overlies the Elbert part, about 1,900 feet thick, has san- Honaker Trail Formation posits. Hermosa Formation (Fig. SU-6). The Ouray is 100 feet thick in the western dy limestone and clayey sandstone Jurassic System Group Paradox Formation and related rocks 1 part of the Reservation and pinches out in the eastern part of the Res- at its base and contains some lime- PENNSYLVANIAN The Entrada Sandstone unconformably overlies the Dolores Forma- Pinkerton Trail Formation stone or limy beds in its lower 600 ervation. It is composed of dark-brown to light-gray, dense, argilla- tion and is composed of light-gray, cross-bedded sandstone. Maxi- feet; it grades upward into fine- Molas Formation ceous limestone with local green clay partings. mum thickness is about 250 feet. The overlying Morrison Formation grained shaly sandstone. The Lower Mississippian Leadville Limestone unconformably is composed of two members, the Salt Wash Member which is most- MISSISSIPPIAN Leadville Sandstone overlies the Ouray Limestone. The Leadville ranges in thickness ly sandstone with interbedded claystone and mudstone, and the over- Ouray Limestone from nearly zero on the east side of the Reservation to about 250 feet lying Brushy Basin Member which is mostly varicolored claystone DEVONIAN Elbert Formation on the west side. The Leadville is composed of yellowish-brown and and mudstone. Maximum thickness of the Morrison Formation is light to dark-gray finely to coarsely crystalline, fossiliferous dolo- about 800 feet. CAMBRIAN Ignacio Quartzite mite and limestone. The Leadville formed during two transgressive episodes in the Mississippian. The sediments were deposited under Cretaceous System PRECAMBRIAN The Early Cretaceous Burro Canyon Formation disconformably a variety of depositional environments ranging from shallow water Figure SU-6. Geochronologic chart for the San Juan Basin. Yellow units are productive in the tidal flats to low-energy stable-shelf conditions to high-energy overlies the Morrison Formation. Like the Jurassic rocks, the Burro Southern Ute Indian Reservation (modified after Gautier et al., 1996). shoals. Another unconformity separates the Leadville Limestone Canyon is exposed only at the northeast corner of the reservation. It is about 1000 feet thick in the Reservation and consists of lenticular

SOUTHERN UTE INDIAN RESERVATION Stratigraphic Overview 3 COLORADO Overlying the Mancos Shale is the series of interbedded sandstones grained sandstone, limestone, calcareous concretions, and bentonite. land Shale and the Animas Formation, which overlies it on most of mas is characterized by conglomerate beds, containing boulders and of the Late Cretaceous Mesaverde Group. It is composed of the It crops out on the west side of the Reservation in a northeast-trend- the Reservation, is transitional and arbitrary. pebbles of andesite in a tuffaceous matrix. Interbedded with variegated Point Lookout Sandstone, the Menefee Formation, and the Cliff ing band marked by Long Hollow, and on the east side in a wide sin- shale and sandstone. On the west side of the Reservation the McDer- House Sandstone (Fig. SU-6). The Mesaverde Group forms several uous zone that trends northwest from Archuleta Mesa. Thickness of Cretaceous and Tertiary Systems mott Member (Late Cretaceous) has a maximum thickness of 290 feet, small mesas in the northeastern part of the reservation. The outcrop the Lewis ranges from 1,440 to 1,825 feet on the west side if the Immediately overlying the Kirtland shale over most of the Reserva- which thins to the south and east. The upper member (Paleocene) has continues to the west in an arc north of the reservation, and reenters Reservation, and increases eastward to about 2,400 feet on the east tion is the Animas Formation. It ranges in age form Late Cretaceous- a maximum of 2,670 feet near the La Plata-Archuleta County line it on the west side, where the Cliff House Sandstone lies at the sur- side. Early Paleocene but in the southeastern part of the Reservation it is (north of the Reservation), and thins to 1,840 feet on Cat Creek. face of nearly all the reservation west of the La Plata River. The Late Cretaceous Pictured Cliffs Sandstone was deposited only Paleocene. The Animas Formation crops out in a band of varia- The Point Lookout Sandstone, at the base of the Mesaverde during the final regression of the epeiric Cretaceous sea during Cam- ble width forming an east-west arc across the Reservation. The Ani- Group, conformably overlies and is transitional with the Mancos panian time (Figs SU-6, SU-7). It forms a hogback from Cinder

Shale. In the area of the Reservation, the Point Lookout Sandstone Buttes to Bridge Timber Mountain on the west side of the Reserva- SSW 146 MILES (235 KILOMETERS) NNE is divided into a lower sandstone and shale member and an upper tion, and on the east side forms the lower part of the steep northeast- NEW MEXICO COLORADO massive sandstone member. The sandstone and shale member is facing slopes that extend form Archuleta Mesa to the Piedra River. ZUNI UPLIFT SAN JUAN BASIN about 80-125 feet thick and is composed of interbedded yellowish In its western exposures the formation is from about 215 feet to 285 SAN JUAN MTNS

AH UT AH SAN JUAN GAS FIELD gray, fine-grained, cross-laminated sandstone and sandy dark-olive- feet thick. The Pictured Cliffs is divided into an upper part that con- COLO Pagosa TERT. gray, fossiliferous shale; the amount of sandstone in the member in- sists of one or more massive sandstone beds interbedded with some N. MEX Springs

ARIZ Tertiary Ojo Alamo Sandstone Farmington

and younger rocks Maastr icht creases upward toward the overlying massive sandstone member. thin shale beds and a lower transitional zone composed of relatively SAN JUAN Kirtland Shale The upper massive sandstone member is about 200-250 feet thick thin intercalations of sandstone and shale. The lower transitional BASIN Cuba

and is composed of thick to massive beds of light-gray to yellowish- zone consists of thin, grayish-orange and light-olive-gray, very fine A A Gallup ? ZUNI RE gray, crossbedded, fine- to medium-grained sandstone. The contact grained sandstone, interbedded with subordinate amounts of gray UPLIFT

with the overlying Menefee Formation is conformable and sharp in shale and siltstone. The upper part is composed primarily of dark- Grants Albuquerque RAL Friutland Formation NE most places. yellowish-orange and light-gray, medium- to thick-bedded, ledge- 0 25 Miles GE Pictured Cliffs Sandstone ZUNI The Menefee Formation consists of a series of interbedded lens- forming sandstone. The formation thins eastward to 90 feet on Klut- IN BASIN 0 25 Kilometers es of sandstone, siltstone, shale, and coal. Irregular bedding and rap- ter Mountain just east of the Reservation, but the general lithology E INDEX MAP C A id lateral changes of lithology are characteristic of the formation. remains the same. The contact with the overlying Fruitland Forma- METERS FEET Huerfanito Bentonite Bed URF ? 600 2,000 The sandstones and siltstones are various shades of light gray and tion is conformable, with local intertonguing. S Kcht Cliff House Sandstone yellowish gray and range in grain size from coarse sand to very fine The Late Cretaceous Fruitland Formation is a sequence of inter- Lewis Shale 500 ION La Ventana Campanain S silt. The shales are mostly shades of dark gray or brown. The coal bedded and locally carbonaceus sandstones, siltstones, shales, coal 1,500 OER Cliff House beds are lenticular and in many places grade both horizontally and and locally in the lower part of the formation, thin limestone beds. 400 VERT. EXAG.=84 Tongue } Sandstone Menefee Formation Y vertically into carbonaceous clay shale and carbonaceous shaly sand- The lithology of the formation is characterized by lateral discontinui- A 300 1,000 D T-N stone. Thin coal beds occur throughout the formation, but most coal ty, most individual beds pinching out within a few hundreds of feet. E

200 ES Mesaverde Group UPPER CRETACEOUS beds more that 1.2 feet thick are in the lowermost 50-60 feet of the The coal beds, are more continuous and may be traced for several R 500 P Allison Member formation, and a few are immediately below the top. The Menefee miles. Although coal beds occur throughout the formation, the thick- 100 Point Lookout Sandstone Cleary Coal Member thins to the northeast and pinches out in the eastern part of the Reser- est and most persistent beds are in its lower part. The limestone beds ? vation. are found only in the lowermost part of the formation, sandstone is 0 0 Kph The Cliff House Sandstone is a sandstone and shale sequence in usually more abundant in the lower part than in the upper part, and Satan Tongue Mancos Shale the vicinity of the Reservation. The unit consists of sandstone, silt- siltstone and shale predominate the upper part. The formation ranges Gibson Coal Koda Crevasse Canyon Member stone, and shale in varying proportions, with sandstone becoming form about 300 to 500 feet thick on the west side of the Reservation, Formation Tocito Sandstone Lentil San.Con. thicker toward the southwest. On Weber Mountain, a few miles but thins eastward to about 300 feet in its outcrop area on the east Kcbp Mulatto Tongue northwest of the Reservation, the Cliff House consists of an upper side. The contact with the Kirtland is gradational, and most geolo- Gallop Sandstone sandstone unit 65 feet thick, a middle shaly unit 210 feet thick, and a gists place the top at the highest bed of coal or carbonaceous shale. ota Ss Graneros Member Lopez Member Turon. Tongue of Dak lower sandy unit 70 feet thick. The shaly unit wedges out within a The Late Cretaceous Kirtland Shale is divided into a lower shale ? ? Mancos Bridge Creek Limestone Member Paguate

Shale Cen. few miles southward; as a result, the subsurface Cliff House Sand- member, a middle sandstone unit called the Farmington Sandstone Twowella Tongue of Dakota Ss stone at and beneath the surface in the western part of the Reserva- Member, and an upper shale member. In the western part of the Res- Clay Mesa Tongue of Mancos Shale tion may be presumed to be predominantly sandstone. The total Dakota Sandstone ervation, the lower shale member consists of olive- to medium-gray Whitewater Arroyo Tongue of Mancos Shale thickness is about 400 feet, but some of this has been eroded where sandy shale that commonly contains lenses of nonresistant olive- EXPLANATION the formation is at the surface. The Cliff House Sandstone interfin- gray, fine grained sandstone. The lower member also contains thin gers laterally and vertically with the overlying marine Lewis Shale lenses of carbonaceous shale and abundant amounts of silicified Nonmarine rocks Kph Hosta Tongue of Point Lookout Ss

and with the underlying deltaic deposits of the upper member of the wood at various horizons. The Farmington Member on the western Marine and coastal sandstone Kcda Dalton Ss Mbr of Crevasse Canyon Fm Menefee Formation. part of the Reservation is a sequence of resistant sandstones that are Marine shale, siltstone, and minor amounts of sandstone and limestone Kcbp Borrego Pass Sandstone Lentil of Crevasse The Late Cretaceous Lewis Shale is a marine shale that was de- separated by beds of shale. The upper shale member on the western Canyon Formation posited in late Campanian time (Figs. SU-6, SU-7). It consists pri- part of the Reservation consists of shale and interbedded lenses of Kcht Sandstone exposed at Tsaya Canyon Time Marker bed, e.g., bentonite or calcareous zone marily of light-to dark-gray and black shale with interbeds of fine- nonresistant, friable sandstone. The age of the Kirtland is Late Creta- Figure SU-7. Stratigraphic cross section showing upper Cretaceous rocks across the San Juan Basin, New Mexico and Colorado (modified ceous (Campanian to Maastrichtian). The contact between the Kirt- after Nummedal and Molenaar, 1995).

SOUTHERN UTE INDIAN RESERVATION Stratigraphic Overview 4 COLORADO Production Overview structures. The stratigraphic section of the San Juan Basin attains a maximum thickness of approximately 15,000 ft in the northeast part Oil and gas production in the San Juan Basin was described in of the structural basin where the Upper Devonian Elbert Formation the “1995 National Assessment of United States Oil and Gas Resour- lies on Precambrian basement. Elsewhere in the province Cambrian, ces” (Gautier, D.L., et al., 1996). All plays discussed in the “Play Mississippian, Pennsylvanian, or Permian rocks may overlie the Pre- Summary Overview” are defined by that publication. The “Play cambrian. Summary Overview” combines the research from that publication Plays were defined primarily on the basis of stratigraphy because along with other recent publications in the Southern Ute Indian Res- of the strong stratigraphic controls on the occurrence of hydrocar- ervation. The following is a summary of the San Juan Basin Prov- bons throughout the province. In general, the plays correspond to ince as described in “1995 National Assessment of United States Oil lithostratigraphic units containing good quality reservoir rocks and and Gas Resources” with connections to source beds. In the central part of the basin, po- rosity, permeability, stratigraphy, and subsurface hydrodynamics San Juan Basin Province control almost all production, whereas around the flanks, structure and stratigraphy are key trapping factors. The San Juan Basin province incorporates much of the area from Although most Pennsylvanian-age oil and gas is on structures latitude 35° to 38° N. and from longitude 106° to 109° W. and com- around the northwestern margin, hydrocarbons commonly accumu- prises all or parts of four counties in northwest New Mexico and six late only in highly porous limestone buildups. Jurassic oil on the counties in southwestern Colorado (Huffman, 1996). It covers an southern margin of the basin is stratigraphically trapped in eolian area of about 22,000 sq mi (Fig. SU-8). strata at the top of the Entrada Sandstone. Almost all oil and gas in Almost all hydrocarbon production and available subsurface data Upper Cretaceous sandstones of the central basin is produced from are restricted to the topographic San Juan Basin. Also included in stratigraphic traps. Around the flanks of the basin, some of the same the province, but separated from the structural and topographic San Cretaceous units produce oil on many of the structures. Juan Basin by the Hogback monocline and Archuleta arch, respec- Seven conventional plays were defined and individually assessed tively, are the San Juan Dome and Chama Basin, which contain sedi- in the province; Porous Carbonate Buildup (2201), Marginal Clastics mentary sequences similar to those of the San Juan Basin. In much (2203), Entrada (2204), Basin Margin Dakota Oil (2206), Toci- of the San Juan Dome area the sedimentary section is covered by var- to/Gallup Sandstone Oil (2207), Basin Margin Mesaverde Oil (2210), iable thicknesses of volcanic rocks surrounding numerous caldera and Fruitland-Kirtland Fluvial Sandstone Gas (2212). The Porous Carbonate Buildup Play (2201) is assessed as part of play 2102 in the Paradox Basin; similarly, Permian–Pennsylvanian Margin- al Clastics Gas Play (2203) is assessed as part of play 2104 in the Paradox Basin, so is not discussed further here. Eight unconventional plays were also assessed--five continuous-type plays and three coalbed gas plays. Con- tinuous-type plays are Fractured Interbed (2202), Dakota Central Basin Gas (2205), Mancos Fractured Shale (2208), Figure SU-9. Locations of oil and gas production wells, cumulative through 1993 (modified after Gautier et al., 1996). Central Basin Mesaverde Gas (2209), and Pictured Cliffs Gas (2211). Also present is the continuous-type Fractured Interbed Play (2103) which is described and assessed in Southern Ute Indian Reservation Paradox Basin Province (021). Coal-bed gas plays are San UT CO AZ NM Juan Basin–Overpressured (2250), San Juan Ba- sin–Underpressured Discharge (2252), and San Juan Ba- SAN JUAN sin–Underpressured (2253). The plays of interest to the BASIN Southern Ute Indian Reservation are described in the “Play PROVINCE Summary Overview”.

0 50 Miles

Figure SU-8. Location of U.S.G.S. San Juan Basin Province with respect to the Southern Ute Indian Reservation (modified after Gautier et al., 1996).

SOUTHERN UTE INDIAN RESERVATION Production Overview 5 COLORADO Play Types Summary of Plays Conventional Plays- Discrete Deposits, usually bounded by a downdip water The United States Geological Survey identifies several petroleum plays in the contact, from which oil, gas or NGL can be extracted using traditional San Juan Basin Province and classifies them as Conventional or development practices, including production at the surface from a well as a Unconventional. The discussions that follow are limited to those with direct consequence of natural pressure within the subsurface reservoir, artificial lifting significance for future petroleum development in the Southern Ute Indian of oil from the reservoir to the surface where applicable, and the maintenance of Reservation. reservoir pressure by means of water or gas injection

Unconventional Plays- A broad class of hydrocarbon deposits of a type (such as gas in “tight” sandstones, gas shales, and coal-bed gas) that historically has not been produced using traditional development practices. Such accumulations include most continuous-type deposits.

Total Production Reservation: Southern Ute San Juan Basin Cumulative Totals Undiscovered resources and numbers of fields are Geologic Province: Paradox & San Juan Basin Oil: >240,000,000 BO for Province-wide plays. No attempt has been made Province Area: Paradox Basin (33,000 sq. miles) San Juan Basin (22,000 sq. miles) Gas: >18,000,000,000 CFG to estimate number of undiscovered fields within the Reservation Area: 553,008 acres NGL: Included Southern Ute Indian Reservation. (figures from NMOGA, 1997 & FCGS, 1983) USGS Drilling depths Play Type Description of Play Oil or Gas Known Accumulations Undiscovered Resource (MMBOE) Play Probability Designation Field Size (> 1 MMBOE) median, mean (chance of success) (feet) Mounds of algal limestone in the Both Gas (448,740 MMCFG) Gas (10 BCFG, 131 BCFG) 1.0 Gas (4000, 6000, 14000) 1 Porous Carbonate Paradox Formation of the Oil (521,090 MBO) Oil (4 MMBO, 6.3 MMBO) Oil (2500, 6000, 14000) 2102,2201 Hermosa group. Buildup Play

Associated with relict dune Oil (4,360 MBO) Oil (2 MMBO, 1.8 MMBO) 1.0 Oil (3000, 6000, 9000) 2 deposits on top of the Jurassic Oil 2204 Entrada Sandstone. Entrada Play

2206 Mostly upper marine part of the Both Gas (62,100 MMCFG) Gas (10 BCFG, 12.1 BCFG) 1.0 Gas (1000, 2000, 2000) 3 Dakota sandstone. Oil (22,589 MBO) Oil (2 MMB0, 2.8 MMBO) Oil (600, 2000, 5000) Basin Margin Dakota Oil Play

Lenticular sandstone bodies of Both Gas (199,800 MMCFG) Gas (30 BCFG, 38.0 BCFG) 1.0 Gas (4000, 6000, 8000) 4 2207 Upper Cretaceous Tocito and Oil (174,135 MBO) Oil (4 MMBO, 6.3 MMBO) Oil (1000, 5000, 8000) Gallup Sandstones. Tocito-Gallup Sandstone Oil Play

Intertonguing of porous marine Oil 5 2210 sandstone at base of the Upper Gas (7.8 BCFG, estimated mean) Oil (2 MMBO, 1.9 MMCO) 0.8 Oil (300, 2000, 4000) Cretaceous Point Lookout Oil (7.8 MMBO, estimated mean) Basin Margin Sandstone with the organic rich upper Mancos Shale. Mesa Verde Oil Play

Lenticular fluvial sandstone bodies Gas 6 Fruitland-Kirtland 2212 enclosed in shale source rocks Gas (1,505,520 MMCFG) Gas (18 BCFG, 23.2 BCFG) 1.0 Gas (1000, 2000, 4000) and (or) coal. Fluvial Sandstone Gas Play

Table 1. Play summary chart.

SOUTHERN UTE INDIAN RESERVATION Summary of Play Types 6 COLORADO Total Production Reservation: Southern Ute San Juan Basin Cumulative Totals Undiscovered resources and numbers of fields are Geologic Province: Paradox & San Juan Basin Oil: >240,000,000 BO for Province-wide plays. No attempt has been made Province Area: Paradox Basin (33,000 sq. miles) San Juan Basin (22,000 sq. miles) Gas: >18,000,000,000 CFG to estimate number of undiscovered fields within the Reservation Area: 553,008 acres NGL: Included Southern Ute Indian Reservation (figures from NMOGA, 1997 & FCGS, 1983) USGS Drilling depths Play Type Description of Play Oil or Gas Known Accumulations Undiscovered Resource (MMBOE) Play Probability Designation Field Size (> 1 MMBOE) median, mean (chance of success) (feet) 7 Coastal marine barrier-bar sandstone Gas (8211.28 BCFG) and continental fluvial sandstone units, (estimated mean) N / A Gas (5000, 6900, 8000) Dakota Central Basin 2205 primarily within the transgressive Gas 1.0 Gas Play Dakota Sandstone.

8 Fractured organic rich marine Mancos Gas (94.42 BCFG) Shale. (estimated mean) Mancos Fractured 2208 Oil Oil (188.85 MMBO) N / A 1.0 Oil (1000, 3000, 7000) Shale Play (estimated mean)

Sandstone buildups associated with Gas (7,000 BCFG) 9 stratigraphic rises in the Upper Gas (1000, 2600, 5000) Central Basin Cretaeous Point Lookout and Cliff 2209 Gas Mesaverde Gas Play House Sandstones. N / A 1.0

Sandstone reservoirs enclosed in shale 10 or coal at the top of the Pictured Cliffs Gas (3264.04 BCFG) Gas (1000, 2100, 3600) Pictured Cliffs 2211 Sandstone. Gas (estimated mean) 1.0 Gas Play N / A

North-Central part of the basin and 11 north of the structural hingeline where Coal Bed Gas Play: recharge of fresh water takes place. N / A 1.0 Gas (500, 2809, 4200) 2250 Gas Gas (4165.41 BCFG) Overpressured Play (estimated mean)

South of the structural hingeline of the 12 basin where coal beds are Coal Bed Gas Play: 2252 underpressured. Gas 1.0 Underpressured N / A Gas (500, 1402, 4000) Discharge Play Gas (2143.84 BCFG) (estimated mean)

Eastern part of the basin where ground 13 water flow is sluggish. Gas (1223.78 BCFG) Gas (estimated mean) 1.0 Gas (500, 2446, 4000) Coal Bed Gas Play: 2253 N / A Underpressured Play

Table 2. Play summary chart - continued

SOUTHERN UTE INDIAN RESERVATION Play Types (continued) 7 COLORADO ARCO SO. UTE 33-11 No. 1 SEC. 10, T33N, R11W Two logs were chosen to represent the stratigraphy of the Southern Ute Indian Well #1 KB 6,910 FT

Reservation. Their locations are marked on the figure below. Together they 5400 Tertiary 6 represent the stratigraphy from Devonian - Tertiary. The logs show the 5500 undivided 5600 SP/Gamma and Resistivity profile of their respective rock units. TERTIARY Organ Rock Fm 1 5700 5800 5900

Kirtland Shale Cedar Mesa SS 6000

and 6100

Mancos Shale mian

related rocks 6200

6300 Per 6400 7 Well #1 ARCO S. Ute 33-11 No. 10-1 Juan Lopes Mbr. Halgaito Fm 6500 Sec 10, T33N, R11W 6600

(Molenaar, C.M., and Baird, J.K., 1989) 2 ? 6700 6 ? 00 8 6900 CRETACEOUS CRETACEOUS Well #2 GENERAL PETROLEUM CORP. No. 55-17 Kikel Fruitland Formation Bridge Creek Ls. Rico Fm Sec 17, T34N, R11W, Graneros Mbr. 7000 (Condon, S.M., and Huffman, A.C., 1994) 7100 Dakota S.S. 7200 Pictured Cliffs SS 7300

TD 7,875 FT 7400 0

EXPLANATION 7500

GR Honaker Trail Fm 7600 unconformity 300 3 7700

Well # 2 GR N 7800 3100 7900 depositional contact Dakota SS 3200 8000

600 feet 3300 Brushy Basin Mbr 8100

3400 anian 8

Morrison 20 0 3500 Fm Westwater Canyon Mbr 8300 R15W R1W Lewis Shale 3600 8400

Salt Wash Mbr 3700 8500

3800 assic

CRETACEOUS CRETACEOUS ennsylvP

8600 r

Junction Creek SS 3900

Well #2 8700 Ju 4 Wanakah Fm 4000 8800 Entrada SS 4100 Paradox Fm 8900 4200 9000

4300 and Southern Ute Indian Reservation T33N 9100

4400 related rocks

CO 9200 4500

NM Well #1 9300 4600 9400 N Dolores Fm 4700 9500

4800 iassic

9600 r

R16W T30N R1W R1E 4900 Pinkerton Trail Fm T 9700

5000 Molas Fm Fig. SU-10 Location of Type Logs in Southern Ute Indian Reservation. 5 .Miss 9800

Menefee Fm. 5100 Leadville Ls 9900 5200

Ouray Ls 10000 Organ Rock Fm 5300

Point Lookout S.S Devon.

SOUTHERN UTE INDIAN RESERVATION Type Logs 8 COLORADO Porous Carbonate Buildup Play vary considerably. Most oil discoveries are in the 1–100 MMBO lated to the Hogback lineament. (USGS 2201) size range and include associated gas production. The largest fields, Akah Stage rocks are not considered to be an exploration Tocito Dome and Tocito Dome North, have produced a total of objective within the reservation because salt and anhydrite General Characteristics about 13 MMBO and 26 BCFG. Eight significant nonassociated and deposition was dominate at this time. The Akah Stage repre- The Porous Carbonate Buildup Play in this province is primarily a associated gas fields have been developed in the play, the largest of sents the maximum extent of evaporite limits (Fig. SU-10). gas play and is characterized by oil and gas accumulations in which, Barker Creek, has produced 205 BCFG. The Pennsylvanian Desert Creek Stage carbonates were deposited in a defin- mounds of algal (Ivanovia) limestone associated with organic-rich is basically a gas play and has a moderate future potential for medi- able arcuate trend around the southeast terminus of the basin. A' black shale rimming the evaporite sequences of the Paradox Forma- um-size fields. The Desert Creek is bounded by the Chimney Rock and tion of the Hermosa Group. Most developed fields within the play Gothic Shales which represent transgressions. Growth of the produce from combination traps on the Four Corners platform or in Desert Creek carbonate bank occurred during slow subsi- the Paradox Basin province, but for this analysis, the play was ex- dence of the Paradox Basin. Source rocks for hydrocarbons Southern Ute Indian Reservation Characteristics of the Porous Carbonate Buildup Play UT CO tended southeast to the limit of the black shale facies, roughly corre- In the Southern Ute Indian Reservation, the Paradox Formation is are the Chimney Rock and Gothic Shales (Fig. SU-10). AZ NM sponding to the limit of the central San Juan Basin. conformably bounded by the Pinkerton Trail Formation at its base The Ismay Stage is divided into lower and upper units. SAN JUAN Reservoirs: Almost all hydrocarbon production has been from vug- and the Honaker Trail Formation at its top (Fig. SU-3). It ranges The lower unit is bounded by the Gothic and Hovenweep BASIN gy limestone and dolomite reservoirs in five zones of the Hermosa from 800 feet thick in the south to 1700 feet thick in the north. The Shales (Fig. SU-10). During the Ismay Stage the southern Group: (in ascending order) the Alkali Gulch, Barker Creek, Akah, Paradox Formation was deposited during Desmoinesian age of the part of the basin was slowly subsiding. Oil is produced from PROVINCE Desert Creek, and Ismay. The zones gradually become less distinct Pennsylvanian Period under strong cyclic conditions involving trans- algal carbonate buildups. The upper unit is bounded by the toward the central part of the San Juan Basin. Net pay thicknesses gressive and regressive movements of the Pennsylvanian sea. The Hovenweep and Boundary Butte Shales (Fig. SU-10). Pro- generally vary from 10 to 50 ft and have porosities of 5-20 percent. transgressive phase is represented by black organic rich dolomitic duction is from algal or bioclastic/biogenic reservoirs. The 0 50 Miles source rocks for Ismay rocks are the Gothic, Hovenweep, and Source rocks: Source beds for Pennsylvanian oil and gas are be- muds while the regressive phase is represented by carbonate A Boundary Butte Shales. lieved to be organic-rich shale and laterally equivalent carbonate mounds. Reservoirs within the reservation are biogenic/bioclastic Figure SU-11. Location of the Porous Carbonate Buildup Play (modified after rocks within the Paradox Formation. The presence of hydrogen sul- carbonate mounds deposited in shoaling areas of an evaporite basin. Gautier et al., 1996). The four main cycles of Desmoinesian deposition are the Barker fide (H2S) and appreciable amounts of CO2 at the Barker Creek and A A' NE Ute Dome fields probably indicates high-temperature decomposition Creek, Akah, Desert Creek, and Ismay Stages (Fig. SU-10). Southern SW Ute Durango- of carbonates. Correlation of black dolomitic shale and mudstone Barker Creek Stage strata have a gross thickness of 500 feet. It Reservation Hermosa- Rockwood Quarry units of the Paradox Formation with prodelta facies in clastic cycles is a fossiliferous, algal, dolomitic limestone with vuggy, secondary 14,15, 18 present in a proposed fan delta complex on the northeastern edge of dolomite. Most reservoir rock is algal, dolomitic limestone with en- the Paradox evaporite basin helps to account for the high percentage hanced porosity and permeability due to dolomitization and weather- ing. The Barker Creek was deposited on paleostructural features re- of kerogen from terrestrial plant material in black shale source rocks. Arizona New Mexico New Mexico Colorado 128 277 259 247 131 125 Timing and migration: In the central part of the San Juan Basin, 325 323 317 307 293 Pennsylvanian sediments entered the thermal zone of oil generation HONAKER TRAIL FORMATION Bonito Canyon 203 during the Late Cretaceous to Paleocene and the dry gas zone during Upper part Boundary Butte 39 Organ Rock Formation the Eocene to Oligocene. It also is probable that Pennsylvanian ISMAY De Chelly Hovenweep Shale STAGE Sandstone Lower part source rocks entered the zone of oil generation during the Oligocene Gothic Shale DESERT CREEK Cedar Mesa Sandstone throughout most of the Four Corners Platform. Updip migration and STAGE Chimney Rock local migration from laterally equivalent carbonates and shale beds Supai Haligaito Formation in areas of favorable reservoir beds predominate, and remigration AKAH PARADOX Formation STAGE may have occurred in areas of faulting and fracturing. PrecambrianHermosa Formation Rico Formation Traps: Combination stratigraphic and structural trapping mecha- Rocks nisms are dominant among Pennsylvanian fields of the San Juan Ba- Mississippian and lower Palezoic r Honaker Trail Formation sin and Four Corners Platform. Most fields are located on structures, HERMOSA GROUP

PARADOX FORMATION FORMATION PARADOX EVAPORITES although not all of these structures demonstrate closure. The struc- BARKER CREEK FEET STAGE

UNCOMPAHGRE CUTLER ARKOSE CUTLER ARKOSE UNCOMPAHGRE 1000 tures themselves may have been a critical factor in the deposition of Paradox Formation bioclastic limestone reservoir rocks. Seals are provided by a variety 800 600 ocks of mechanisms including porosity differences in the reservoir rock, 400 Pinkerton Trail Formation overlying evaporites, and interbedded shale. Most production on the 200 Figure SU-10. Stratigraphic chart of the Pennsylvanian Hermosa Four Corners Platform is from depths of 5,100 to 8,500 ft, but minor 0 Group illustrating the Paradox Formation facies changes across 0 2 4 6 8 10 MILES Molas Formation production and shows in the central part of the San Juan Basin are the basin. Each stage is bounded by a time stratigraphic marker from as deep as 11,000 ft. bed of sapropelic, dolomitic mudstone. These markers are Exploration status and resource potential: Field sizes in the play continuous and mappable throughout the basin (modified after Figure SU-12. Cross section showing southwest-northeast correlations of Pennsylvanian and Permian rocks in the San Juan Harr, 1996). Basin and adjacent areas. Line of section is shown in Figure SU-11 (modified after Condon, 1992).

SOUTHERN UTE INDIAN RESERVATION CONVENTIONAL PLAY TYPE: Porous Carbonate Buildup Play 9 COLORADO EXPLANATION Halite present + Drill Hole Analog Fields In and Near Reservation SAN JUAN CO Outcrop

AH DOLORES CO MONTEZUMA CO LA PLATA CO (*) denotes field lies within the reservation boundaries UT Anh MILES KILOMETERS COLORADO ydrite present * Wildwater + + 2100 Blac (see Figure SU-16) + 2000 + k Shale Present CONEJOS CO + ARCHULETA CO R 13 W + + 1900 Location of discovery well: ne, sw, sec 2, T34N, R13W (1974) Cortez 18 1800 14 13 1700 16 15 1400+ Durango Pagosa Springs Producing formation: Paradox Formation 1600 + Bayfield 1300 + WILDWATER + + + Type of trap: Structure-Stratigraphic 1200 + + 1500 0' SUPERIOR + 1400 1300 PENNSYLVANIAN FIELD La Posta Ignacio AN CO Red Mesa 1200 + Number of producing wells: 1 (1977) 24-14X MENEFEE + 1000 + 700 + + Pagosa + + 500 1100 Junction 1100 600 Chrono + Initial production: 1040 MCFGD LA PLATA CO., COLORADO 400 SAN JU + + Arboles COLORADO 18 + 1000 0 21 22 23 24 + + RIO ARRIBA CO NEW MEXICO SAN JUAN CO 300 Cumulative Production: N/A 900 + 100 ++ + + + Cedar Hill + +++ + Dulce 200 + 800 + + + + 900 + + + STRUCTURE AND ISOPACH

+ CHE CO + Gas characteristics: BTU 1,165 A + + AP CONTOUR MAP + + + + + + + Oil characteristics: 63 API gravity, light, yellowish green + + + 700 + + 800 + + T + Farmington + Type of drive: Gas expansion STRUCTURE DATUM - TOP OF ISMAY + + + + + 30 500 + 28 0 27 26 25 + 35 INTERVAL - 100' 600 Average net pay: 13 feet Black 400Shale present N ISOPACH OF UPPER ISMAY POROSITY + N + 800 Porosity: 6.6 % ARIZONA + + + 10' INTERVAL - 10' NEW MEXICO Permeability: N/A Figure SU-13. Isopach map of the Paradox Formation and equivalent rocks of the * Alkali Gulch West 31 Hermosa Group. Contour interval is 100 feet (modified after Condon, 1992). 33 35 36 CSO No. 1 FEDERAL "B" Location of discovery well: c, new,sw, sec 2, T33N, R13W (1981) SECTION 2-N34N-13W

Producing formation: Ismay Zone of the Paradox Formation -500'

AHUT 0 10 20 Miles Type of trap: Stratigraphic COLORADO + Number of producing wells: 1 (1992) + + + + + + + + 8300 + + + + + 3 2 1 6 + + + + + + + + + Initial production: 1.152 MCFGD, 6BWD + + + + + CSO DAVIS + + ++ + + + + + + DAVIS 1- WILDWATER ++ + + + + + 6000 Cumulative Production: 369,633 MCFG, 423 B condensate (1992) 1-FED. "B" ++ + + + + T + + + + ++ + Cortez 2000 1-MENEFEE + + + + ++ 4000 A' + + + + Gas characteristics: 97.75% methane, 1.23 % ethane, 0.32 % N Buff + + + + + -559 -634 + + ++ + Durango 0' + + 0 + + Pagosa Springs propane A -537 13' + ++ + 0 + + 9 0' 7 34 + + + + + 2000 11 12 + + + + + + + + + Type of drive: Gas expansion + N 8400 + + + ++ + + + + + + + -2000 PAY + + + + + + Average net pay: 66 feet UTAH ZONE + ARIZONA + + + + + + + + + ++ + + + + Porosity: 8% + + + + + + + + -2000 14 + + + ++ + + + + + 6 5 3 2 + + + + + + + + + + + Permeability: N/A 7 8 10' 10 11 ++ + + + + + -4000 -4000 + + + + + + + 2000 + + ++ Wickiup 0 + + + + ZONE ISMAY + + + ++ + 8500 + + + + + Location of discovery well: sw se sec 24, T33N, R14W (1972) + + Farmington + + 0 + + + + Producing formation: Barker Creek Zone of the Paradox Formation T + 18 17 16 15 14 + + + + + N Type of trap: Stratigraphic ++ + 34 + + + + + + + ++ + -4000 CSO Number of producing wells: 1 (1977) -1000' 1-STORY "A" N Figure SU-14. Structure contour map of the top of the Rico Formation. Contour Initial production: 1,970 MCFGD, 842 BWD interval is 1000 feet (modified after Huffman and Condon, 1993). 8600

Cumulative Production: 20,603 MCFG (1982) PARADOX Gas characteristics: BTU 914 Type of drive: Gas expansion A' A DAVIS CSO DAVIS Average net pay: 10 feet No. 1 Menefee No. 1 Fed "B" No. 1 Wildwater CREEK ZONE DESERT -200

Porosity: 8% 8700 UTE Permeability: N/A DOME

Barker Creek AKAH ZONE WILD WATER Location of discovery well: se, se, nw, sec 21, T32N, R14W (1945) -500 ALKALI GULCH Producing formation: Paradox Formation CONTOUR DATUM WICKIUP Southern Ute Indian Reservation N Type of trap: Structural Number of producing wells: 5 (1977) ISMAY ZONE CO BARKER CREEK Initial production: 42,000 MCFGD NM DESERT CREEK Cumulative Production: 115,237,890 MCFG, 109,462, B condensate ZONE (1994) -1000 AKAH Gas characteristics: BTU 1,026 sweet gas, BTU 875 sour gas ZONE T30N R16W R1W R1E Type of drive: Solution gas, fluid expansion Average net pay: ± 100 feet (individual pay zones range 10-80 ft) Figure SU-15. Location of oil and gas field discovery wells for fields producing Figure SU-16. Structure contour map, structural cross section, and type log from the Wildwater from the Porous Carbonate Buildup Play. Porosity: 2-10 % (vugs and fractures) Pennsylvanian field (modified after Bevacqua, 1983). Permeability: extremely variable due to vugs and fractures)

SOUTHERN UTE INDIAN RESERVATION ANALOG FIELDS: Porous Carbonate Buildup Play 10 COLORADO Entrada Play field development. Between 1972 and 1977, seven fields similar to Figure SU-18. Media were discovered, primarily using seismic techniques. Areal SOUTH NORTH Time-stratigraphic (USGS 2204) SW Colorado Outcrops sizes of fields range from 100 to 400 acres, and total estimated pro- Ma Zuni Uplift Outcrops San Juan Basin Subsurface chart of stratigraph- CRETACEOUS Jackpile Ss Mbr Burro Canyon Fm 0-60m ic units on the duction of each varies from 150,000 BO to 2 MMBO. A number of 144 Brushy Basin Mbr General Characteristics Brushy Basin Mbr Morrison Fm WESTWATER CANYON MBR Southern Ute Indi- Westwater Canyon Mbr RECAPTURE MBR areas of anomalously thick Entrada in the southeastern part of the Upper 120-275 m The Entrada play in the southeastern part of the San Juan Basin, is Recapture Mbr SALT WASH MBR an Reservation and San Juan Basin have yet to be tested, and there is a good probability Bluff Ss Mbr (NW) Junction Creek Ss 0-75 m Horse Mesa Mbr Wanakah Fm adjacent areas based on relict dune topography on top of the eolian Middle Jurassic Cow Springs Ss 0-75 m BECLABITO Mbr Bilk Cr Ss & Upper Mbr 15-60 m that at least a few of these areas have adequate trapping conditions Middle Todilto Ls Mbr 2-45 m PONY EXPRESS LS MBR (modified after Entrada Sandstone, associated with organic-rich limestone source JURASSIC Entrada Ss 30-90 m rocks and anhydrite in the overlying Todilto Limestone Member of for undiscovered oil accumulations, but with similar development Condon, 1992). Lower Glen Canyon Gp problems as the present fields. Limiting factors to the moderate fu- 208 ? ? the Wanakah Formation. North of the present producing area, in the Owl Rock Mbr ? Chinle Fm ture oil potential of the play include the presence of sufficient paleo- Petrifies Forest Mbr Dolores Fm deeper, northeastern part of the San Juan Basin, porosity in the En- Upper SONSELA SS BED 150-500 m ? topographic relief on top of the Entrada, local structural conditions, Monitor Butte Mbr trada decreases rapidly. Compaction and silica cement make the En- TRIASSIC Shinarump Mbr Shinarump Mbr trada very tight below a depth of 9,000 ft. No eolian sandstone hydrodynamics, source-rock and oil migration history, and local po- buildups have been found south and west of the producing area. rosity and permeability variations Figure SU-19. Isopach SAN JUAN CO Reservoirs: Some of the relict dunes are as thick as 100 ft, but have AHUT DOLORES CO map of the Entrada Characteristics of the Entrada Play MONTEZUMA CO LA PLATA CO flanks that dip only 2 degrees. Dune reservoirs are composed of + Drill Hole Sandstone. Contour The Entrada Play does not yet produce in the Southern Ute Indian COLORADO Outcrop fine-grained, well-sorted sandstone, massive or horizontally bedded + interval is 50 feet Reservation. The Entrada Sandstone and Wanakah Formation are 150 + + + + 100 (modified after Condon, in the upper part, and thinly laminated, with steeply dipping cross- + + present in the subsurface of the Reservation (Figs. SU-19 & -20). + + + 1992). CONEJOS CO bedding in the lower part. Porosity (23 percent average) and perme- + ARCHULETA CO The Entrada Formation is composed of two members, the Dew- + Cortez 100 + + + ability (370 md average) are very good throughout. Average net pay + + ey Bridge Member and the Slick Rock Member (Condon, 1992). + Durango 150 Pagosa Springs + in developed fields is 23 ft. ++ + + Bayfield The Dewey Bridge member is 25-35 feet thick in the western side of ++ ++ + + + + 200 Source rocks: Limestone in the Todilto Limestone Member has + + + the Reservation; it pinches out eastward. The Dewey Bridge Mem- + + 100 La Posta Ignacio AN CO + + + + + + ++ Red Mesa + been identified as the source of Entrada oil. There is a reported cor- ber is composed of brick-red to reddish-brown, very fine grained, ar- 100 + Pagosa + + Junction + + + + Chrono SAN JU + Arboles relation between the presence of organic material in the Todilto + ++ + + COLORADO gillaceous sandstone and siltstone. The sediments of the Dewey + + + + + + + + + + ++ + SAN JUAN CO RIO ARRIBA CO NEW MEXICO Limestone and the presence of the overlying Todilto anhydrite. This + + + + Dulce Bridge were deposited in a sabkah environment that bordered the Ju- + +++ + + + Cedar Hill 100 + + + + 150 + + + + 250 + + + association limits the source rock potential of the Todilto to the + + + rassic sea, which was present to the north and west of Colorado. The CO ACHE + + + + + AP + + + deeper parts of the eastern San Juan Basin. Elsewhere in the basin, + + Slick Rock Member consists of white, pinkish-orange, and reddish- + + 100 + + + the limestone was oxygenated during deposition and much of the or- + + orange, very fine to fine grained, locally medium grained sandstone. + Farmington + + + + + + + ganic material destroyed. + + Bedding is medium to thick with alternating cosets of cross bedded 100 + 150 + 150 ++ Timing and migration: Maximum depth of burial throughout most and flat-bedded strata. The Slick Rock averages 70-100 feet in + N + + + 200 200 150 of the San Juan Basin occurred at this time. In the eastern part of the thickness in the subsurface of the Reservation. The sediments of the ARIZONA +

NEW MEXICO + + basin, the Todilto entered the oil generation window during the Oli- Slick Rock were deposited in an extensive area of eolian dunes and gocene. Migration into Entrada reservoirs either locally or updip to interdunes that bordered the Jurassic sea. + Drill Hole SAN JUAN CO the south probably occurred almost immediately; however, in some AHUT DOLORES CO MONTEZUMA CO LA PLATA CO Outcrop fields, remigration of the original accumulations has occurred subse- COLORADO quent to original emplacement. +

Traps: All traps so far discovered in the Entrada Sandstone are + + CONEJOS CO + + + ARCHULETA CO stratigraphic and are sealed by the Todilto limestone and anhydrite. Cortez 40 0 20 + Figure SU-20. Isopach Local faulting and drape over deep-seated faults has enhanced, modi- + + 60 + Durango Pagosa Springs map of the Todilto + Bayfield fied, or destroyed the potential closures of the Entrada sand ridges. 20 + + 80 Limestone Member of + + Hydrodynamic tilting of oil-water contacts and (or) "base of movable + + the Wanakah La Posta Ignacio + AN CO + + Red Mesa oil" interfaces have had a destructive influence on the oil accumula- + + Formation and + + + Pagosa Junction + Southern Ute Indian Reservation + + Chrono Equivalent rocks. tions because the direction of tilt typically has an updip component. SAN JU + + Arboles + UT CO + 120 COLORADO + + + RIO ARRIBA CO Contour interval is 20 AZ NM + ++ SAN JUAN CO NEW MEXICO All fields developed to date have been at depths of 5,000–6,000 ft. + + + Dulce + + + + + Cedar Hill ++ + 60 feet (modified after 0 + + + + + + + + + + Because of increase in cementation with depth, the maximum depth + + + + + + Condon, 1992). ACHE CO ACHE + + + + + AP + at which suitable reservoir quality can be found is approximately + + + + + + + + 100 + + + + 9,000 ft. + + ++ Farmington + + + + + + + + Exploration status and resource potential: The initial Entrada + + + + + + + discovery, the Media field, was made in 1953 (Gautier, et al, 1996). + + + + + 60 + 80 + 40 80 + + + 60 Development was inhibited by problems of high water cut and high ARIZONA 20 20 pour point of the oil, problems common to all subsequent Entrada Figure SU-17. Location of the Entrada Play (modified after NEW MEXICO + 40 Gautier, Dolton, Takahashi, and Varnes, 1996).

SOUTHERN UTE INDIAN RESERVATION Entrada Play 11 COLORADO Basin Margin Dakota Oil Play typically formed by updip pinchout of porous sandstone into shale or (USGS 2206) coal. Structural traps on faulted anticlines sealed by shale form some of the larger fields in the play. Oil production ranges in depth from 7000 General Characteristics 6000 1,000 to 3,000 ft. 5000 3000 The Basin Margin Dakota Oil Play is both a structural and strati- 4000 1000 2000 4000 Exploration status and resource potential: The first discoveries in -10000 graphic play on the northern, southern, and western sides of the cen- the Dakota play were made in the early 1920's on small anticlinal tral San Juan Basin. Because of the variability of depositional envi- structures on the Four Corners Platform. Approximately 30 percent ronments in the Dakota Sandstone, it is difficult to characterize a of the oil fields have an estimated total production exceeding 1 1000 typical reservoir lithology. Most production has been from the up- 3000 -400 MMBO, and the largest field (Price Gramps) has production of 7 0 per marine part of the interval, but significant amounts of both oil 2000 MMBO. Future Dakota oil discoveries are likely as basin structure -1500 and gas also have been produced from the nonmarine section. and Dakota depositional patterns are more fully understood. Reservoirs: The Late Cretaceous Dakota Sandstone varies from 0 12 Miles dominantly nonmarine channel deposits and interbedded coal and The Basin Margin Dakota Oil Play conglomerate in the northwest to dominantly shallow marine, com- The Dakota Sandstone is a coastal plain deposit laid down in front of Figure SU-21. Structure contour map of the base of the Dakota Sandstone in the Southern Ute Indian monly burrowed deposits in the southeast. Net pay thicknesses the advancing Mancos Sea. The oldest unit of the Dakota Sandstone Reservation. Contour interval is 1000 feet except for -1500 foot contour. Southeastern part of the Reservation has no data (modified after Andersen, 1992). range from 10 to 100 ft; porosities are as high as 20 percent and per- on the Southern Ute Indian Reservation is the lower Cenomanian En- meabilities are as high as 400 md. cinal Canyon Member (Fig. SU-24). It consists of alluvial deposits Source rocks: Along the southern margin of the play, the Creta- that fill the valleys at the sub-Dakota unconformity. It was deposited This distribution of depositional environments is consistent with ments. Deltaic rocks on the western part of the Reservation and ceous marine Mancos Shale was the source of the Dakota oil. API by aggradation of Dakota streams in response to rising base level shoreline trends (Fig.25). North-south shoreline trends suggest that shore-zone rocks in the eastern part are probably lateral equivalents, gravities range from 44 to 59. On the Four Corners Platform to the during the earliest stages of the T-1 transgression. depositional environments in the subsurface on the Reservation are deposited during a stillstand of the shoreline. The Dakota is a trans- west, nonmarine source rocks of the Menefee Formation were iden- The Encinal Canyon Member is characteristically a trough-cross similar to those in the Durango and Coldwater Creek areas north of gressive unit in the Reservation area; the fluvial rocks of the Encinal tified as the source. The stratigraphically higher Menefee is brought bedded, fine- to medium-grained sandstone that is commonly con- the Reservation. Canyon are overlain by deltaic rocks and shore zone rocks that are, in into close proximity with the Dakota across the Hogback monocline. glomeratic at its base. Tabular-planar crossbeds and, more rarely, The shore-zone deposits that overly the Encinal Canyon Mem- turn, overlain by the marine Mancos Shale. Timing and migration: Depending on location, the Dakota Sand- horizontal or low-angle laminations also occur at some locations. ber in the Coldwater Creek and Durango areas are composed of fine Reservoirs on the Dakota Sandstone are controlled by stratigraph- stone and lower Mancos Shale entered the oil window during Oligo- The Encinal Canyon member is overlain by delta-plain deposits in grained, bioturbated, and flat-bedded or ripple-laminated sandstone ic and structural trapping. Successful exploration for lower Dakota cene to Miocene. In the southern part of the area, migration was still the Four Corners and Durango areas, by shore-zone deposits in the probably deposited in tidal-flat, shoreface, or offshore-bar environ- Sandstone production is obtained by careful mapping of channel sand- taking place in the late Miocene time or even more recently. Coldwater Creek and Durango areas (north of the Reservation on the ments. Coal may have been deposited in coastal swamps, and silt- stones and close attention to oil and gas shows in the thin, porous stone and mudstone may represent lagoonal or offshore environ- sandstone that may develop in channels. Traps: Fields range in size from 40 to 10,000 acres and most pro- eastern side), and by marine deposits in northwestern New Mexico. duction is from fields of 100-2,000 acres. Stratigraphic traps are SW NE NW SE

Greenhorn Limestone Greenhorn Limestone

Mancos Shale Graneros Shale Mancos Shale Graneros Member Mancos Shale Twowells Twowells Twowells Twowells Sandstone tongue Twowells ota Dak ota main Paguate Ss. Whitewater Arryo tongue bod y Mancos Shale } } Clay Mesa Shale Paquate Sanstone tongue Paguate Ss.

Clay Mesa Shale tongue Cuber Burro Cany Encinal Can ota Sanstone main o Sandstone body on Fm. y on ota Sandstone

Dak Saltw Cubero Sandstone tongue ash Member Oak Can Mancos Shale } Dak Southern Ute Indian Reservation yon Member UT CO Brush

ota Ss. ota Ss. y Basin Member AZ NM Oak Canyon Member Jac Encinal Canyon Dak kpile Sandstone } Westwater Can lower strata Jz Jackpile Sandstone SAN JUAN Burro Canyon Formation y BASIN Zuni SsSaltwash Member Brushy Basin Member Recapture Memberon Member

PROVINCE . Westwater Canyon Member lower strata Recapture Member ison Fm. ison Fm. Morr Morr 0 50 Miles Figure SU-23. Southwest - northeast schematic stratigraphic cross section relating Figure SU-24. Northwest - southeast schematic stratigraphic cross section relating Figure SU-22. Location of the Basin Margin Dakota Oil Play (modified after members of the Dakota Sandstone and Mancos Shale and adjacent units in the San Juan members of the Dakota Sandstone and Mancos Shale and adjacent units in the San Juan Gautier, et al., 1996). Basin (modified after Whitehead, 1993). Basin (modified after Whitehead, 1993).

SOUTHERN UTE INDIAN RESERVATION Basin Margin Dakota Oil Play 12 COLORADO 114 109 104 40 Analog Fields In and Near Reservation (*) denotes field lies within the reservation boundaries

Grand Junction e PRICE GRAMPS FIELD s Price Gramps e n il e c y Delta ra (see figure SU-27) g osb Byrd-Frost Inc. Hughes Hughes es m Montrose SOUTHERN UTE Hughes Hughes Hughes Hughes r s Location of discovery well: SE, SE, sec24, T33N, R2E (1935) #1-Taylor #33 #32 #7 oce era #49 #12-27 #46 n oc INDIAN A Hughes Hughes Hughes po Hughes A' ci olc RESERVATION Producing formation: Cretaceous Dakota Sandstone #11 #31 #51 S #18 Met Monticello Hughes Hughes Type of trap: Faulted asymmetric anticline #161 #44 9000' Durango Pagosa Springs Number of producing wells: 24 (1977) 37 Chama Initial production: 217 BOD 8000' Farmington Tierra Amarilla Cumulative Production: 6, 716,434 BO (1992) Taos Oil characteristics: c, 60 pour point m 7000' inu Los Alamos r Crownpoint Type of drive: Partial water drive au it Gallup Sante Fe Average net pay: 30 feet an c SEBOYETA BAY s 6000' a Grants Porosity: 14.6 % ave., 4% min., 21.1% max. Albuquerque

er A

oc c C Permeability: 100 mD

a o yc nli GRAMP'S FAULT l n

t n h oce 5000' Ca P o ra l c sta Sedimentary Rocks Igneous and Metamorphic Rocks es e rra r ntense Middle Canyon Dakota ia a 34 s ca Socorro Alluvium Lewis Shale Morrison Fm. n a Volcanic Rocks th lv Location of discovery well: NE, SW, sec 14, T32N, R15W (1969) oc a r 4000' er ad Blanco Basin Mesaverde Grp assic Todilto Fm. a Igneous and s Producing formation: Cretaceous Dakota Sandstone a o Fm urJ Metamorphic 0 1000 2000 3000 f e 4000 ft f. n w s Mancos Upper Shale Entrada Ss. Rocks yo e Type of trap: Stratigraphic m SCALE in ge Number of producing wells: 1 (1977) Mancos Sh (Niabrara Fm) n s Carlile e Mancos Sh Initial production: 122.64 BOD, 7BWD ( Juana Lopez) Cretaceous Mancos Sh Greenhorn Cumulative Production: 4886 BO (1977) ( Graneros ) Geologic cross-section of the Gramps anticline. Oil characteristics: N/A Dakota Ss. Type of drive: Water drive T-1 TRANSGRESSION Average net pay: 20 feet Dakota Shorelines Porosity: 12.1% ave. STRUCTURE MAP Ages Dakota Shelf Sandstones Ammonite Range Zones Permeability: 0.30 mD ave. + 5000' DATUM' SEA LEVEL + 4500' Sciponoceres gracile CONTOUR INTERVAL=500' Late Cenomanian Metolcoceras mosbyense Two Wells Sandstone Sierra R2E R3E Calycoceras canitaurinum Two Wells Sandstone Location of discovery well: SE, NW, sec 5, T35N, R13W (1957)

Plesiacanthoceras aff. wyomingense Paguate Sandstone 5500' + A Producing formation: Cretaceous Dakota Sandstone Middle Cenomanian Acanthoceras alvaradoense + Conlinoceras tarrantense Type of trap: Stratigraphic + 6000' Cubero Sandstone 13 18 W.E. GRAMPS 51 Early Cenomanian - Encinal Canyon Member Number of producing wells: 12 (1992) NW - SE 24- 33N - 2E Initial production: 969 MCFGD Figure SU-25. Map showing positions of the western shoreline of the Western Cumulative Production: 1,299,016 BO (1992), 29,021 MCFG + Interior Seaway during deposition of the upper part of the Dakota Sandstone during + 6500' + + 6000' + + + + the middle and late Cenomanian. Shoreline trends are based on the distribution of Oil characteristics: 35 API gravity 900 + + GREENHORN ammonite fossils found in the lower part of the Mancos Shale, which interfingers Type of drive: solution gas, downdip water encroachment + + with the Dakota Sandstone (modified after Aubrey, 1991). Average net pay: 22 feet + 7000' + 6500' + T Porosity: 18-20% +

+ 33 1000 Permeability: 700 mD A' N GRANEROS Sierra Menefee Mountain + + + 6000' 1100 Menefee Mountain Location of discovery well: NW, NE, NW, sec 16, T35N, R13W Producing formation: Cretaceous Dakota Sandstone + 6000' Type of trap: Structural, stratigraphic + + 6000' + 7000' DAKOTA Number of producing wells: 3 (1983) +5500 Southern Ute Indian Reservation Price + 1200 36 31 Gramps Initial production: 26 BOD, 11 BWD Middle + 6500' CO Canyon Cumulative Production: 49,230 BO, 255 MCFG (1992) NM Oil characteristics: 34.0 API gravity MORRISON Type of drive: water USGS Ryder 1300 N + 6000' Average net pay: 15 feet GR IND + 6000' T30N Porosity: 12-14% R16W R1E Permeability: unknown Figure SU-26. Location of oil and gas field discovery wells for fields producing Figure SU-27. Structural cross section, structure contour map, and type log for the Price Gramps Field (modified from the Basin Margin Dakota Oil Play. after Donovan, 1978).

SOUTHERN UTE INDIAN RESERVATION ANALOG FIELDS: Basin Margin Dakota Oil Play 13 COLORADO Tocito-Gallup Sandstone Oil Play late Eocene time and gas generation in Oligocene time. Migration (USGS 2207) updip to reservoirs in the Tocito Sandstone Lentil and regressive Characteristics of the Tocito-Gallup Oil Play Gallup followed pathways similar to those determined by present General Characteristics structure because basin configuration has changed little since that In recent years a sequence stratigraphic framework The Tocito-Gallup Sandstone Oil Play is associated with lenticular time. has been applied to the Tocito and Gallup Sandstones sandstone bodies of the Upper Cretaceous Gallup Sandstone and To- Traps: Almost all Gallup production is from stratigraphic traps at near the Southern Ute Indian Reservation (Fig. SU-30). cito Sandstone Lentil, and Mancos Shale source rocks lying immedi- depths between 1,500 and 5,500 ft. Hospah and Hospah South, the This framework helps explain hydrocarbon occurrence ately above an unconformity. The play covers almost the entire area largest fields in the regressive Gallup Sandstone, are combination and the stratigraphic traps associated with these units. of the province. Most of the producing fields are stratigraphic traps stratigraphic and structural traps. The Tocito sandstone stratigraphic The northern extent of the Gallup Sandstone production is along a northwest-trending belt near the southern margin of the cen- traps are sealed by, encased in, and intertongue with the marine Man several miles south of the Indian reservation where the tral part of the San Juan Basin. Almost all production has been from Southern Ute Indian Reservation cos Shale. Similarly, the fluvial channel Torrivio Member of the unit is truncated by the Tocito Sandstone. For this reason, UT CO the Tocito Sandstone Lentil of the Mancos Shale and the Torrivio Gallup is encased in and intertongues with finer grained, organic- the Gallup Sandstone will not be included in the following AZ NM A' Member of the Gallup Sandstone. rich coastal-plain shales. description. 0 25 50 miles Reservoirs: The Tocito Sandstone Lentil of the Mancos Shale is the Exploration status and resource potential: Initial Gallup field dis- Since the late 1950’s, 130 MMBOE have been pro- major oil producing reservoir in the San Juan Basin. The name is ap- coveries were made in the mid 1920's; however, the major discover- duced from the Tocito. The Tocito Sandstone marks a N plied to a number of lenticular sandstone bodies, commonly less than ies were not made until the late 1950's and early 1960's in the deeper significant change from shoreface/coastal plain depositio- 50 ft thick, that lie on or just above an unconformity and are of unde- Tocito fields, the largest of which, Bisti, covers 37,500 acres and has nal systems which prevailed throughout Gallup deposi- A termined origin. Reservoir porosities in producing fields range from estimated total ultimate recovery of 51 MMBO. Gallup producing tion. The Tocito Sandstone is a transgressive sequence set 4 to 20% and average about 15%. Permeabilities range from 0.5 to fields are typically 1,000 to 10,000 acres in area and have 15 to 30 ft internally composed of four high-frequency sequences. In 150 md and are typically 5 to 100 md. The only significant produc- of pay. About one-third of these fields have an estimated cumulative ascending order, they are Tocito-1, Tocito-2, Tocito-3 and tion from the regressive Gallup Sandstone is from the Torrivio Mem- production exceeding 1 MMBO and 1 BCF of associated gas. All of Tocito-4 (Fig. SU-30). In the subsurface, the Tocito is Figure SU-29. Location of the Tocito-Gallup Sandstone Oil Play. Cross section ber, a lenticular fluvial channel sandstone lying above, and in some the larger fields produce from the Tocito Sandstone Lentil of the distributed into narrow and elongate bodies which trend A-A' is shown in Fig. SU-28. (modified after Gautier, et al., 1996). places scouring into the top of the main marine Gallup Sandstone. Mancos Shale and are stratigraphically controlled. South of the zone northwest-southeast (Figs. SU-31 and SU-32). Isopach Source rocks: Source beds for Gallup oil are the marine Upper of sandstone buildups of the Tocito, the regressive Gallup Sandstone maps of the Tocito units show that the Tocito-3 and Toci- to-4 are the only units beneath the southern Ute Indian Cretaceous Mancos Shale. The Mancos contains 1-3 weight percent produces primarily from the fluvial channel sandstone of the Torri- BEAUTIFUL MOUNTAIN SUBSURFACE organic carbon and produces a sweet, low-sulfur, paraffin-base oil vio Member. The only large fields producing from the Torrivio are Reservation. OUTCROP that ranges from 38 to 43 API gravity in the Tocito fields and from the Hospah and Hospah South fields, which are combination traps. The high-frequency sequences of the Tocito Sand- Similar, undiscovered traps of small size may be present in the stone contain the lowstand, transgressive, and usually 24 to 32 API gravity farther to the south in the Hospah and Hospah TOCITO South fields. southern half of the basin. The future potential for oil and gas is highstand systems tracts. There are sequence boundaries TOCITO-4 SB at the base of each high-frequency sequence represented Torrivio Timing and migration: The upper Mancos Shale of the central part thought to be low to moderate. by irregular erosional surfaces that truncate into the under- Nonmarine lithofacies of the San Juan Basin entered the thermal zone of oil generation in TOCITO-3 SB lying units. Above the erosional surfaces are incised val- ASW NE ley fill deposits representing the lowstand systems tracts. A' TOCITO-2 SB The top of the valley fills represent transgressive flooding Shallow-marine Tocito-4 SB surfaces and the passage from valley-filling sedimentation GALLUP Tocito-3 SB Tocito-4 SB to open-marine/shelfal sedimentation and the onset of the Tocito-2 SB TOCITO-1 SB FS N1 marker Tocito-3 SB transgressive systems tracts. The transgressive systems JUANA LOPEZ MBR FS Valley-fill FS tracts are overlain by distal marine shales of the highstand N1 M1 marker systems tracts (Tocito-1 and Tocito-2 only). Due to their Gallup SS Tocito-2 SB TST parasequence M1 Tocito-1 SB close vertical juxtaposition, the four Tocito sequences are Valley-fill FS collectively interpreted as components of a sequence set. base Gallup SS Tocito-1 SB Juana Lopez Mbr The four sequences are thought to reflect higher-order cy- cles in relative sea level which were superimposed on a JUANA LOPEZ MBR open marine shale 100 ft longer term cycle. shallow marine sandstone The hydrocarbon trapping is the result of stratigraphic fluvial/distributary/bay fill sandstone V.E.=293x relationships. Structural dip is uniformly toward the carbonaceous shale Juana Lopez Mbr well location northeast and consequently provides only minor influence estuarine sandstone 0 on the pooling of hydrocarbons. The four main trapping calcareous/fosiliferous sandstone 0 5 miles elements are: truncation by younger sequence boundary, Figure SU-30. Composite stratigraphic summary comparing the outcrop and the Figure SU-28. Detailed regional cross section showing high-resolution stratal geometries defined by the key stratigraphic surfaces of arcuate bends in valleys, up-dip valley termination, and subsurface expression of the Gallup and Tocito interval (modified after Jennette the Tocito Sandstone. Position of the cross section is shown in Fig. SU-29 (modified after Jennette and Jones, 1995). and Jones, 1995).

SOUTHERN UTE INDIAN RESERVATION Tocito-Gallup Sandstone Oil Play 14 COLORADO R15W Analog Fields In and Near Reservation R14W R13W R1W R1E T SOUTHERN T (*) denotes field lies within the reservation boundaries 37 N 37 UTE N 33N 33N 33N 33N 33N 33N 33N 33N 33N 33N 33N 20W 19W 18W 17W 16W 15W 14W 13W 12W INDIAN 10W 9W 10 10 RESERVATION Albino Gallup (see figure SU-34) 20 32N 20 Location of discovery well: NC, NE, sec 26, T32N, R8W (1974) 20W 30 30 Producing formation: Gallup sandstone of the Mancos Shale 32N 20 20N 20 Type of trap: Structural, Stratigraphic 30 30 Number of producing wells: 1 (1994) 20 31N 10 Initial production: 2.9 MMCFGD THINNED BY TOCITO 4 TRUNCATION10 20W 10 0 Cumulative Production: 254,377 MCFG (1994) 0 10 Gas characteristics: N/A Red Mesa Southern Ute Indian Reservation 0 0 Type of drive: Gas expansion 30N RATTLESNAKE Chromo 20W T 32 Albino Gallup T Average net pay: up to 900 feet of fractured interval N 32 10 CO N 10 Porosity: 3-8%, and fractures T T HOGBACK 0 10 TOCITO 3 SEQUENCE 32 NM Cinder 32 29N NET FILL ISOPACH Permeability: fracture permeability N Buttes N TOCITO 3 20W CONTOUR INTERVAL 10 FEET 0123456 THINNED BY TOCITO 4 TRUNCATION20 Verde 30 MILES Gallup 28N 40 LEGEND Cinder Buttes N 50 Horseshoe 20W THE SHIPROCK 10 INCISED VALLEY FILL Location of discovery well: SE, SE, SW, sec 13, T32N, R12W (1966) Gallup Flora Vista Gallup Knickerbocker 60 PARTIALLY TRUNCATED BY Producing formation: Cretaceous Gallup Sandstone Meadows Gallup Buttes 0 OVERLAYING SEQUENCE R16W R1W R1E 70 Type of trap: Fractured sandstone, structural-stratigraphic Figure SU-33. Location of oil and gas field discovery wells for fields producing from the Tocito-Gallup Figure SU-31. Isopach map and cross section of the Tocito-3 sequence. The Number of producing wells: 3 (1987) Sandstone Oil Play. contoured interval of the Isopach Map is the Tocito-3 sequence boundary to the Tocito-4 Initial production: 302 MCFGD sequence boundary. Interval thickness of ten feet and greater is highlighted. The cross Cumulative Production: 42,130 MCFG (shut in 1987) section is a transverse section across the Tocito-3 Waterflow Valley (modified after Gas characteristics: 1,176 BTU Jennette and Jones, 1995). Type of drive: Depletion Average net pay: 30 feet (divided among 6-8 thin sandstone beds) Porosity: 16% estimated Permeability: unknown SOUTHERN DISCOVERY WELL 30 30 33N 33N 33N 33N 33N 33N 33N 33N 33N UTE 33N 33N 40 13W 20W 19W 18W 17W 16W 15W 14W 40 12W INDIAN 10W 9W Verde Gallup RESERVATION Location of discovery well: SE, SE, sec 14, T31N, R15W (1955) 40 40 LONE STAR R 8 W R 7 W -1250' No. 1 Schalk 94 32N Producing formation: Fractured interval, Cret. Gallup Sandstone -1275' 20W 30 NE/4, Sec 26-T32-R8W 32N Type of trap: Fractured shale, stratigraphic KB 6793' 20N Number of producing wells: 27 (1977) T 40 32 -1300'

20 Initial production: 180 BOD 7000' 40 N -1325' 31N 30 Cumulative Production: 7,963,004 BO, 174,956 MCFG (1994) 20W 30 20 30 40 Oil characteristics: 38 -42 API gravity 20 0 30 Gas characteristics: sweet high BTU -1400' 0 30 30N 40 Type of drive: Gravity drainage 20W RATTLESNAKE 50 Average net pay: Variable -1325' 10 60 GALLUP HOGBACK20 50 Porosity: Fracture PRODUCING -1325' 30 TOCITO 4 SEQUENCE INTERVAL 29N INCISED VALLEY FILL ISOPACH Permeability: Unknown -1375' 20W 20 CONTOUR INTERVAL 10 FEET

0123456 7500' 40 MILES 0 10 LEGEND Flora Vista Gallup T 28N THE SHIPROCK INCISED VALLEY FILL DISCOVERY WELL -1350' 20W 20 20 50 32 -1325' 0 20 40 50 PARTIALLY TRUNCATED BY Location of discovery well: SE, SW, sec 2, T30N, R12W (1961) 30 OVERLAYING SEQUENCE -1350' 20 20 Producing formation: Cretaceous Gallup Sandstone N 20 PALEOCURRENT DIRECTION Type of trap: Stratigraphic -1300' Figure SU-32. Isopach map and cross section of the Tocito-4 sequence. The contoured Number of producing wells: 3 (1977) INDUCTION ALBINO "GALLUP" -1275' SP RESISTIVITY interval of the Isopach Map is the Tocito-4 sequence boundary to the overlying flooding Initial production: 1,070 MCFGD -1325' FIELD OUTLINE surface. Interval thickness of thirty feet and greater is highlighted. The cross section is a Cumulative Production: 11,114,501 MCFG, 133,026 B condensate transverse section across the Tocito-4 Rattlesnake Valley (modified after Jennette and 8000' (1994) GREENHORN -1350' Jones, 1995). Oil characteristics: BTU 1,303 GRANEROS Type of drive: Solution gas Average net pay: 9 feet DAKOTA R 8 W R 7 W Porosity: 9-12%, 10% ave. (sonic log calculated) Permeability: unknown DTD 8405' COMP 1-24-74 I.P.F MMCFGPD *Red Mesa (poor historical data) COMMINGLED GALLUP/DAKOTA *Chromo (poor historical data) Figure SU-34. Structure contour map, and type log from Albino Gallup Field (modified after Middleman, 1983). (Fassett, 1978,1983; Wells and Lay, 1997)

SOUTHERN UTE INDIAN RESERVATION ANALOG FIELDS - Tocito - Gallup Sandstone Oil Play 15 COLORADO Basin Margin Mesaverde Oil Play area in the State of New Mexico, the Seven Lakes Field, was discov- vironments and the shoreface/delta front environments. These sand- JEROME McHUGH (USGS 2210) ered by accident in 1911 when a well being drilled for water pro- stones are least influenced by carbonate cementation, and appear least SOUTHERN UTE NO.3 NW NW SEC.20, T.32N., R.9W. duced oil from the Menefee Formation at a depth of approximately sensitive to increased confining stress. Reservoir characteristics of General Characteristics 350 ft. The only significant Mesaverde oil field , Red Mesa, was dis- the Point Lookout show that the sandstones are conventional rather Lewis Shale The Basin Margin Mesaverde Oil Play is a confirmed oil play around covered in 1924. than tight. Measured porosity in the 1HCMS well range from 4.2- 5100 the margins of the central San Juan Basin. Except for the Red Mesa 20.5 percent and 6.6-20.4 percent in the 2HCMS well. Measured am- field on the Four Corners platform, field sizes are very small. The The Basin Margin Mesaverde Oil Play bient permeabilities are 0.0003-56.3 md for the 1HCMS well and play depends on intertonguing of porous marine sandstone at the in Southern Ute Indian Reservation 0.0007 to 59.3 md in the 2HCMS well. Higher permeabilities are 5200 Cliff House base of the Upper Cretaceous Point Lookout Sandstone with the or- more common in the upper shoreface and shoreface/delta-front depo- transition ganic-rich upper Mancos Shale. The Cliff House and Point Lookout Sandstones are the producers in sitional environments. Diagenesis also influence reservoir quality. the Basin Margin Mesaverde Oil Play in the Southern Ute Indian The highest amounts of carbonate cement are generally in the lower 5300 Reservoirs: Porous and permeable marine sandstone beds of the Reservation (Fig. SU-37). The Point Lookout shoreface prograded in to middle shoreface environment. There is a general increase in car- basal Point Lookout Sandstone provide the principal reservoirs. The a staircase fashion across the basin, as a series of steps and risers until bonate cement directly above and below many of the shale breaks. thickness of this interval and of the beds themselves may be control- it reached its seaward depositional limit (Fig. SU-36). At this limit, The Cliff House Sandstone consists of several linear sandstone 5400 led to some extent by underlying structures oriented in a northwest- there is a change in the stacking pattern of genetic sequences from complexes (Fig. SU-36). The thicker parts are connected by thin erly direction. seaward-stepping to landward-stepping. This marks the beginning of sandstone sheets; where these sheets are absent, the Lewis Shale rests Source rocks: The upper Mancos Shale intertongues with the basal the Cliff House shoreface aggradation (Fig. SU-36). Reservoir-quali- directly on the Menefee Formation. The depositional environments 5500 ty sandstones in the two vertically stacked shorefaces at the turn- present in the Cliff House Sandstone are fluvial/estuarine, shoreface, Menefee Point Lookout Sandstone and has been positively correlated with oil Formation produced from this interval. API gravity of Mesaverde oil ranges around position are 70 m thick. and delta front. The Cliff House Sandstone benches are composed of 5600 from 37 to 50. The Point Lookout Sandstone is the most extensive regressive homogeneous, mud-free sandstone dominated by amalgamated hum- marine Cretaceous sandstone in the San Juan Basin. Formed during mocky and swaley cross stratification.) Timing: Around the margin of the San Juan Basin, the upper Man- shoreline regression, it covers virtually the entire basin. Its shoreline cos Shale entered the thermal zone of oil generation during the Oli- Point Lookout trended northwest-southeast and prograded toward the northeast in a B Bench 5700 gocene. Sandstone series of thick, imbricated, sandstone units. Straight, wave dominat- C Bench Traps: Structural or combination traps account for most of oil pro- ed shoreface and delta-front deposits form the bulk of the sandstone; D Bench 5800 duction from the Mesaverde. Seals are typically provided by marine tidal, foreshore, and offshore sandstones are lesser constituents. shale, but paludal sediments, or even coal of the Menefee Formation Cores 1HCMS and 2 HCMS (Figs. SU-38 thru 40) show fluvial/es- Transition may also act as the seal. tuarine, shoreface, and delta-front deposits of the Point Lookout interval 5900 Exploration status and resource potential: The first oil-producing Sandstone. The best reservoir sandstones, in terms of porosity and permeability, are found in zones in the upper and lower shoreface en- Upper Mancos GR IND Shale TD 8048' DRL Figure SU-37. Log of the Mesaverde pool SW NE stratigraphic units showing perforated and producing “B” bench reservoir of the Point Lookout Sandstone. Cliff House Sandstone The “A” bench is absent by non-deposition and the “C” and “D” benches are shaley. Well is the Jerome Lewis Shale McHugh Southern Ute No. 3, NW, NW, sec. 20, T32N, R9W, La Plata Co., CO (modified after Keighin, et al., 1993).

Southern Ute Reservation Upper Menefee UT CO AZ NM Lower Menefee

SAN JUAN BASIN PROVINCE out Sandstone Point Look Mancos Shale Figure SU-36. Diagram of the stacking

0 50 Miles patterns of genetic sequences in the Sand-rich Coastal Plain Channelbelt Sandstones Marine Shelf Mesaverde Group, and the temporal relations among the five formations that Figure SU-35. Location of the Basin Margin Mesaverde Oil Play (modified Mud-rich Coastal Plain Shoreface Ravinement surface encompass them (modified after Cross and after Gautier, et al., 1996). Lessenger, 1997).

SOUTHERN UTE INDIAN RESERVATION CONVENTIONAL PLAY TYPE: Basin Margin Mesaverde Oil Play 16 COLORADO COLORADO SOUTHERN UTEINDIAN RESER 37 o

Foreshore ARIZONA UTAH Inner shelf shoreface shoreface shoreface 109 Lower Middle Upper plain coastal Lower Southern Ute Indian Reservation Reservation Indian Ute Southern o N NEW MEXICO COLORADO 1 2 3 mi. 30 20 10 0 1300 1050 1250 1200 1150 1100 1000 950 900 Farmington 1 HCMS VATION 1 HCMS 2 HCMS * 108 San Juan Basin Basin Juan San o Blanco Field Ignacio 2 HCMS Durango 1200 1150 950 900 800 750 1100 1050 1000 850 coastal Lower transition Inner shelf shoreface Lower shoreface lower Distal shoreface upper (?) Middle to delta front Shoreface/ plain Cuba 107 o (modified afterKeighin,etal.,1993). 1HCMS (sec30,T33N,R13W)and2HCMS5,T32N, Blanco gasfield,SouthernUteIndianReservation,anddrillholes Basin asdefinedbytheFruitland-PicturedCliffscontact,Ignacio- Figure SU-38. (modified afterKeighin,etal., 1993). Sandstone, asdeterminedfrom cores;forcoreholes1HCMSand2HCMS Figure SU-40. cores, andinterpreteddepositionalenvironments(modified afterKeighin,etal.,1993). density, ambientandin-situpermeability,calculatedprinciple poresize(PPS),observedlithologyof Figure SU-39. 1200 1100 1300 1150 1050 1250 1000 950 900 .0 .0 .0 2.60 2.40 2.20 2.00 51 52 25 20 15 10 5 0 (g/cm) Bulk Density Porosity (%) IndexmapshowinglocationoftheSanJuan Comparison ofdepositionalfacies inthePointLookout RelationshipinthePointLookoutSandstonebetweenmeasured porosity,bulk 1 HCMS 4 3 2 1 1 2 1 0 -1 -2 -3 -4 4202 Permeability Log insitu Permeability (md) Ambient Log PPS(um) 0 100 * * shoreface Lower shoreface Middle Innershelf Lower shoreface Upper Foreshore plain coastal 1050 1000 1200 1150 1100 950 750 900 850 800 .0 .0 .0 2.60 2.40 2.20 2.00 51 52 25 20 15 10 5 0 Porosity (%) (g/cm) Bulk Density 4 3 2 1 1 2 1 0 -1 -2 -3 -4 4202 Permeability Log insitu Log PPS(um) Permeability (md) Ambient 0 2 HCMS 100 * lower Distal shoreface shoreface upper (?) Middle to transition shoreface Intershelf Lower delta front Shoreface/ Lower plain coastal * Figure SU-41. 32 N T

33 FOUR CORNERS N 34 T tion. (Lauth,1983) mation aboutMesaverdeProductionintheSouthernUteIndianReserva- Mesa field.TheCentralBasinMesaverdePlayprovidesadditionalinfor- Mesaverde production,oilcharacteristics,reservoirquality,etc.intheRed Figure SU-41isalocationmapofthefield.Therenodataavailablefor near theSouthernUteIndianReservation.ThatfieldisRedMesafield. The BasinMarginMesaverdeOilPlayonlyproducesfromonefieldinor N T R-13-W PLA TFORM ALKALI GULCH ALKALI Location mapoftheRedMesa Field (modifiedafterLauth,1983). FIELD FIELD CONVENTIONAL PLAY TYPE: Analog FieldsInandNearReservation NEW MEXICO COLORADO RED MESA MESA RED FIELD FIELD R-12-W Basin Margin Mesaverde Oil Play STATE STATE STATE STATE HOGBA RED MESA FIELD MESA RED LA PLATA COUNTY, COLORADO

CK R.E. LAUTH &E.A. RIGGS LOCATION MAP LINE LINE MONOCLINE BASIN FIELD SAN JUAN R-11-W

17 Fruitland-Kirtland Fluvial Sandstone Gas Play along the western side of the basin suggests a paleofluvial channel Hoppe, 1992). For this reason, the following should be consid- (USGS 2212) system of northeasterly flowing streams. Similar channel systems ered an extremely brief overview. General Characteristics may be present in other parts of the basin and are likely to contain The Fruitland Formation contains up to 50 TCF of coalbed The Fruitland-Kirtland Fluvial Sandstone Gas Play covers the cen- similar amounts of hydrocarbons. Future potential for gas is good, methane in place. Half of this may be producible reserves. The tral part of the basin and is characterized by gas production from and undiscovered fields will probably be in the 2–5 sq mi size range Fruitland pore system ranges from overpressured to underpres- stratigraphic traps in lenticular fluvial sandstone bodies enclosed in at depths between 1,000 and 3,000 ft. sured. The Fruitland Formation lies stratigraphically above the shale source rocks and (or) coal. Production of coalbed methane Because most of the large structures have probably been tested, Pictured Cliffs Sandstone. The Fruitland consists of sandstone, from the lower part of the Fruitland has been known since the future gas resources probably will be found in updip stratigraphic limestone, shale, carbonaceous shale, coal, and volcanic ash. It 1950's. The Upper Cretaceous Fruitland Formation and Kirtland pinchout traps of channel sandstone into coal or shale in traps of represents numerous environments on the coastal plain. Envi- Shale are continental deposits that have a maximum combined thick- moderate size (Gautier et al., 1996). ronments change quickly laterally and include stream, overbank, Southern Ute Indian Reservation ness of more than 2,000 ft. The Fruitland is composed of interbed- floodplain, swamp, and tidal deposits. Production from the UT CO AZ NM ded sandstone, siltstone, shale, carbonaceous shale, and coal. Sand- Characteristics of the Fruitland-Kirtland Fruitland is highly dependent on finding areas where cleating is stone is primarily in northerly-trending channel deposits in the lower Fluvial Sandstone Gas Play preserved or in locating natural fractures. Production is also part of the unit. The lower part of the overlying Kirtland Shale is Many studies have focused on the Fruitland-Kirtland Fluvial Sand- controlled by net thickness of coals. SAN JUAN dominantly siltstone and shale, and differs from the upper Fruitland BASIN stone Gas Play in the past ten years (Harr, 1988; Bland, 1992; and N mainly in its lack of carbonaceous shale and coal. The upper two- PROVINCE 108 107 thirds or more of the Farmington Sandstone Member of the Kirtland R16W 15 14 13 12 11 10 9 8 7 6 5 4 3 2 R1W R1E Shale is composed of interbedded sandstone lenses and shale. LA PLATA T 36 N Reservoirs are predominantly lenticular fluvial channel sand- Durango 0 50 Miles stone bodies, most of which are considered tight gas sands. They MONTEZUMA 20 ARCHULETA 35 are commonly cemented with calcite and have an average porosity 40 30 Figure SU-42. Location of the Fruitland-Kirtland Fluvial Sandstone Gas Play 60 50 of 10-18 percent and low permeability (0.1–1.0 md). Pay thickness 34 (modified after Gautier et al., 1996). ranges from 15 to 50 ft. The Farmington Sandstone Member is typi- 40 T DURANGO 35 cally fine grained and has porosity of 3 to 20 percent and permeabil- N ity of 0.6 to 9 md. Pay thicknesses are generally 10–20 ft. 33 COLORADO 32 Source rocks: The Fruitland-Kirtland interval produces nonassoci- 37 50 T 25 NEW MEXICO 33 70 R 1 W R1E N ated gas and very little condensate. Its chemical composition Outcrop of Fruitland 35 60 Dulce UT CO MONTEZUMA CO. LA PLATA CO. CO ARCHULETA CO. (C1/C1-5) ranges from 0.99 to 0.87 and its isotopic (d13C1) compo- Formation and AZ NM SAN JUAN CO. NM Kirtland Shale 40 sitions range from -43.5 to -38.5 per mil (Rice et al., 1988). Source 31 T 5060 31 TYPE LOG 10 40 N rocks are thought to be primarily organic-rich nonmarine shales en- R 16 W 25 30 FRUITLAND FORMATION 0 30 OUTCROP 15 casing sandstone bodies. 10 FARMINGTON 20 T 70 29 Timing and migration: In the northern part of the basin, the Fruit- 60 20 N 20 land Formation and Kirtland Shale entered the thermal zone of oil 10 30 29 50 40 T 27 generation during the latest Eocene and the zone of wet gas genera- 60 N 50 5 tion probably during the Oligocene. Migration of hydrocarbons up- RIO ARRIA 28 40 dip through fluvial channel sandstone is suggested by gas production 10 T 27 25 N from immature reservoirs and by the areal distribution of production 30 Figure SU-43. Gas- 20 from the Fruitland. SAN JUAN in-place contour map 26 T RIO ARRIEA CO. RIO ARRIEA CO. 10 for the Fruitland 23 AN CO. Traps: The discontinuous lenticular channel sandstone bodies that 10 N 20 20 20 form the reservoirs in both the Fruitland Formation and Kirtland Formation. Contour R19W R17W R15W R13W SAN JU 25 interval is 10 BCFG / T Shale intertongue with overbank mudstone and shale and paludal 36 CUBA 2 21 CO. SANDOVAL 40 mi . (modified after N Gas In-Place Contour Map coals and carbonaceous shale in the lower part of the Fruitland. Al- 20 24 Kelso and Wicks, MC KINLEY CO. 30 2 though some producing fields are on structures, the actual traps are 1988). Contour Interval : 10 BCF/MI 30 T predominantly stratigraphic and are at updip pinchouts of sandstone 40 19 23 N into the fine-grained sediments that form the seals. Most production 20 SAN JUAN BASIN is from depths of 1,500–2,700 ft. Production from the Farmington 10 COLORADO COLORADO AND NEW MEXICO T 22 STUDY 17 AREA N SANDOVAL AL CO. Sandstone Member is from depths of 1,100–2,300 ft. 0 10 20 Miles

NEW MEXICO Exploration status and resource potential: The first commercial- Cuba SANDOV 21 N T 10 1987 15 ly produced gas in New Mexico was discovered in 1921 in the EXPLANATION 0 N

Farmington Sandstone Member at a depth of 900 ft in what later be- Isopach interval: 10 feet COLO 20 McKINLEY came part of the Aztec field. Areal field sizes range from 160 to Area R11W R9W R7W R5W R2W R1W of this N MEX Figure SU-44. Isopach map of total thickness of coal in the Fruitland Formation. 32,000 acres, and almost 50 percent of the fields are 1,000–3,000 0 5 10 15 20 MILES report 19 Contour interval is 10 feet (modified after Fassett, 1988). acres in size. The almost linear northeasterly alignment of fields

SOUTHERN UTE RESERVATION CONVENTIONAL PLAY TYPE: Fruitland-Kirtland Fluvial Sandstone Gas Play 18 COLORADO R15W R1W R1E CALIPER COMPENSATED NEUTRON FORMATION DENSITY SPHERICALLY FOCUSED LOG Analog Fields In and Near Reservation 6(in) 16 FORMATION (ohm-m) (*) denotes field lies within the reservation boundaries GAMMA RAY 3

2.0 (g/cm ) 3.0 1 10 100 1000 0 (API) 200 DEPTH (ft) KIRTLAND *Ignacio Blanco (see Fig. SU-47 ) SHALE Location of discovery well: NE ¼, NW ¼, sec 7, T33N, R7W (1951) Producing formation: Cretaceous Fruitland Formation Type of trap: Structural / Stratigraphic Number of producing wells: 115 (1986) Initial Production: 2,200 MCFGD Cumulative Production: 26,750,352 MCFG (1986) Southern Ute Indian Reservation GR T33N 3100 Gas characteristics: 990 BTU Type of drive: Solution gas CO Glades Los Pinos Caliper 15 NM Cottonwood Average net pay: 16-205 feet, 70 feet average Fruitland Fruitland Fruitland Porosity: 4.4% Sedro Canyon North Conner Fruitland Los Pinos Flora Vista Fruitland, South Permeability: 0 - 1500 md Fruitland Fruitland Aztec Aztec La Jara Wyper North Blanco Farmington Fruitland Fruitland Glades Fruitland R16W T30N Farmington Fruitland 3200 Location of discovery well: NW ¼, MW ¼, sec 36, T32N, R12W (1978) Figure SU-46. Location of discovery wells for fields that produce from the Fruitland- 30 Producing formation: Cretaceous Fruitland Formation upper Kirtland Fluvial Sandstone Gas Play in and near the Southern Ute Indian Reservation. Type of trap: Stratigraphic R10W R9W R8W R7W R6W R5W lower Coal Number of producing wells: 12 (1994) 2 DURANGO T35N Initial Production: 1,002 MCFGD T35N 1500 FRUITLAND FORMATION FRUITLAND 7 Cumulative Production: 1,478,106 MCFG (1994) Gas characteristics: 1,177 BTU T34N 1000 T34N 2 R11W 2000 3300 1900 1900 Average net pay: 20 feet average 500 SOUTHERN UTE Porosity: 8-15% INDIAN RESERVATION 1000 T34N T34N 1000 UP1 Permeability: NA 1000 900 R5W R12W 300 Los Pinos Fruitland, North 1000 IGNACIO 5 1000 Location of discovery well: NE ¼, NE ¼, sec 18, T32N, R7W (1953) 900 T33N 900 T33N Producing formation: Cretaceous Fruitland Formation 900 3400

4 Type of trap: Stratigraphic 800 300 700 400 Number of producing wells: 8 (1994) 500 600 Total coal 65 ft 900 2000 Initial Production: 1,310 MCFGD T32N T32N 1000 Cumulative Production: 2,111,682 MCFG (1994) 800 LA PLATA CO. COLORADO ARCHULETA CO. Gas characteristics: 1,071 BTU 500 SAN JUAN CO. NEW MEXICO T32N T32N Type of drive: Gas expansion R12W R11W R10W R9W R8W R7W R6W Average net pay: 50 feet average 3500 LEGEND IGNACIO BLANCO GAS FIELD Porosity: 12-14% estimated NORTHERN SAN JUAN BASIN, COLORADO Permeability: NA TYPE LOG FOR RESERVOIR N DISCOVERY WELL FRUITLAND RESERVOIR SOUTHERN UTE INDIAN RESERVATION 0 1 2 3 4 5 6 PRODUCING WELLS BOUNDARY Los Pinos Fruitland, South STRUCTURE TOP UPPER MANCOS Location of discovery well: NE ¼, NE ¼, sec 17, T31N, R7W (1953) CONTOUR INTERVAL - 100 FEET

PICTURED CLIFFS SANDSTONE PICTURED CLIFFS SANDSTONE Producing formation: Cretaceous Fruitland Formation LOWER KIRTLAND

3600 Type of trap: Stratigraphic, enhanced by fractures SHALE AMOCO Number of producing wells: 1 (1994) 2400 SOUTHERN UTE GAS UNIT "AC" NO.1 Initial Production: 1,790 MCFGD FRUITLAND SW NE SE Section 18, T33N, R7W Figure SU-45. Identification and measurement of Fruitland Coal in type log (location is labeled FORMATION in figure 44). High natural gamma response, indicated by arrows, are attributed to volcanic ash Cumulative Production: 947,221 MCFG (1994) LA PLATA CO., COLORADO Gas characteristics: 980 BTU beds and to organically bound radioactive elements in coal seams (modified after Ayers et al., 2500 1994). Type of drive: Gas expansion Average net pay: 41 feet average COMPLETED. 3-20-87 Porosity: 11.9% estimated IPP: 76 MCFGD, 117 BWPD

Permeability: 0.96 md 2600 PICTURED CLIFFS ( Fassett, 1978,1983; Lay, 1997) SANDSTONE BULK DENSITY

GR DIND T.D. 2660 DRL Figure SU-47. Structure contour map and log for the Ignacio Blanco gas field. Structure contours are drawn on the top of the upper Mancos Shale, contour interval is 100 feet. (modified after Harr, 1988).

SOUTHERN UTE INDIAN RESERVATION CONVENTIONAL PLAY: Fruitland-Kirtland Fluvial Sandstone Gas Play 19 COLORADO 6,500 to 7,500 ft. Dakota Central Basin Gas Play central part of the basin is saturated with gas, and (USGS 2205) Exploration status and resource potential: The Dakota dis- additional future gas discoveries within the Basin covery well in the central basin was drilled in 1947 southeast of field and around its margins are probable. General Characteristics: The Dakota Central Basin unconventional Farmington, New Mexico, and the Basin field, containing the Da- (Gautier et al. 1996) Southern Ute Indian Reservation continuous-type play is contained in coastal marine barrier-bar sand- kota gas pool, was formed February 1, 1961 by combining several UT CO stone and continental fluvial sandstone units, primarily within the existing fields. By the end of 1993 it had produced over 4.0 TCFG AZ NM Dakota Sandstone. and 38 MMB condensate. Almost all of the Dakota interval in the Reservoirs: Reservoir quality is highly variable. Most of the marine N sandstone reservoirs within the basin are considered tight, in that po- Analog Fields In and Near Reservation (* field lies within the reservation boundaries) rosities range from 5 to 15 percent and permeabilities from 0.1 to 0.25 md. Fracturing, both natural and induced, is essential for effec- * Ignacio Blanco Dakota (see figure SU-50) Barker Creek Dakota tive field development. Location of discovery well: SE, NE, sec 18, T33N, R7W Location of discovery well: SE, NE, sec 16, T32N, (1950) R19W (1925) 0 25 50 miles Source rocks: Quality of source beds for oil and gas is also varia- Producing formation: Cretaceous Dakota Sandstone Producing formation: Upper Cretaceous Dakota ble. Non-associated gas in the Dakota pool of the Basin field was Type of trap: Stratigraphic and Structural Type of trap: Structural generated during late mature and postmature stages and probably had Number of producing wells: 193 (1992) Number of producing wells: 5 (1977) Figure SU-49. Location of the Dakota Central Basin Gas Play (modified after Gautier et al., 1996). a marine Mancos Shale source (Rice, 1988). Initial production: 3,780 MCFGD Initial production: Estimated 10,000-30,000 Cumulative Production: 219,443,282 MCFG (1992) MCFGD ATLANTIC REFINING CO. TYPE

T N T N T N Timing and migration: In the northern part of the central San Juan Gas characteristics: BTU 950-990 Cumulative Production: 22,542,303 MCFG (1994) 34 33 32 So. Ute 32-8 No. 13-1 NE/4 13-32N-8W A Basin, the Dakota Sandstone and Mancos Shale entered the oil gener- Type of drive: Gas expansion, possible water Gas characteristics: Sweet gas, 1,125 BTU La Plata Co., Colorado ation window in Eocene time and were elevated to temperatures ap- drive Type of drive: Gas expansion IP-2, 955 MCFD Average net pay: Variable 10-60 feet Average net pay: 40 feet Archuleta Co. propriate for the generation of dry gas by late Oligocene time. Along La Plata Co. 8000 Porosity: 7.5% ave. Porosity: 14% the southern margin of the central basin, the Dakota and lower Man- R6W Permeability: 0.02-0.7 md intergranular and Permeability: 0-1500 md, 16.5 md ave. cos entered the thermal zone of oil generation during the late Mio- natural fracturing Greenhorn

cene. It is not known at what point hydrodynamic forces reached suf- Graneros 8200 ficient strength to act as a trapping mechanism, but early Miocene Ute Dome Dakota Strait Canyon Dakota

Location of discovery well: SE, sec 35, T32N, R14W (1921) 800 time is likely for the establishment of the present-day uplift and ero- Location of discovery well: NW, SW, sec 14, T31N, IGNACIO Dakota Kd

R7W Producing formation: Cretaceous Dakota Sandstone R16W (1975) 900 Kd "A" 1000 sion pattern throughout most of the basin. Migration of oil in the Da- 1100 Type of trap: Faulted anticline Producing formation: Cretaceous Dakota 1200 kota was still taking place in the late Miocene, or even more recently, 8400 Number of producing wells: 14 (1978) Sandstone Kd "B" in the southern part of the San Juan Basin. Initial production: 12,000 MCFGD Type of trap: Structural GR IND Traps: The Dakota gas accumulation is on the flanks and bottom of Cumulative Production: 18,767,726 MCFG (1994) Number of producing wells: N/A Gas characteristics: Sweet, BTU 1000+ R8W a large depression and is not localized by structural trapping. The Initial production: 303 MCFGD Well Discovery 900 900 1200 1100 Type of drive: Combination water and 1000 NORTHWEST PIPELINE CORP.

Cumulative Production: 114,155 MCFG (1994) 1000 Ignacio 33-7 No. 14-20 fluid transmissibility characteristics of Dakota sandstones are gener- TYPE volumetric Gas characteristics: BTU 1031.0 NW/4 20-33N-7W ally consistent from the central basin to the outcrop. Hydrodynamic Average net pay: 30 feet La Plata Co., Colorado Type of drive: Water NEW MEX. IP- 7,880 MCFD B COLORADO

Porosity: 15% CAOF- 14,262 MCFD forces, acting in a basinward direction, have been suggested as the Average net pay: 12 feet 1000

7400 Greenhorn

700 Permeability: 10 md 900

trapping mechanism, but these forces are still poorly understood. The Porosity: 15% 1100

R9W seal is commonly provided by either marine shale or paludal carbona- Permeability: 0.66-17 md, 10 md avg. 800 Graneros (Fassett, 1978,1983; Well and Lay, 1997) ceous shale and coal. Production is primarily at depths ranging from *Red Mesa

(poor historical data) Dakota R15W R1W Kd "A" 7600

R10W

Kd "B" BONDAD BONDAD

Basal Kd 7800

Ignacio R11W Blanoo

N GR IND Dakota

T33N Southern Ute Indian Reservation Figure SU-50. Structure map and logs for the Ignacio DAKOTA POOL CO Blanco Gas Field. Structure Contours are drawn on DATUM: 2000' BELOW SEA LEVEL BONDAD - IGNACIO FIELD NM Barker Creek Dakota Note: La Plata & Archuleta Counties, Colorado the base of the Greenhorn. Kd “A” is littoral marine B production north of line CONTOURED ON BASE OF GREENHORN Strait Ute Dome Dakota Figure SU-48. Location of discovery sandstones while Kd “B” is paludal-fluvial sandstones A production south of line Canyon wells for fields producing from the Dakota (modified after Bowman, 1978). CONTOUR INTERVAL 100' Dakota Central Basin Gas Play. R16W T30N R1W R1E

SOUTHERN UTE INDIAN RESERVATION CONVENTIONAL PLAY TYPE: Dakota Central Basin Gas Play 20 COLORADO Mancos Fractured Shale Play Oil reservoirs associated with the Mancos Fractured Shale Play (USGS 2208) depend on secondary porosity and permeability provided by the frac- A A' tures. The reservoirs are lithologically controlled only to the extent SW NE General Characteristics that brittle competent interbeds capable of fracturing are present. The Mancos Fractured Shale Play (Fig. SU-51) is a confirmed, un- The fractures have greater lateral, than vertical continuity. The basic Dalton SS conventional, continuous-type play (Gautier et al., 1996). It is de- tools used in exploration for fracture permeability are structure con- NIOBRARA pendent on extensive fracturing in the organic-rich marine Mancos tour maps and lithofacies maps showing brittle interbeds in domi- Shale. Most developed fields in the play are associated with anticli- nantly shaly sequences. Upper Mancos Shale nal and monoclinal structures around the eastern, northern, and west- Trap types are structural/stratigraphic - fracture traps. The reser- ern margins of the San Juan Basin (Fig. SU-52). voirs are primarily driven by gravity drainage. Borrego Pass Lentil "Skelly" zone (Stray SS) Reservoirs: Reservoirs comprise fractured shale and interbedded Tocito SS Lentil coarser clastic intervals at approximately the Tocito Lentil strati- Dilco graphic level. Source rocks: The Mancos Shale contains 1-3 weight percent or- ganic carbon and produces a sweet, low-sulfur, paraffin-base oil that Bisti Field ranges from 33 to 43 API gravity. Gallup Gallegos Field CARLILE Timing: The upper Mancos Shale of the central part of the San Juan Basin entered the thermal zone of oil generation in the late Eocene and of gas generation in the Oligocene. Lower Mancos Shale Traps: Combination traps predominate. Traps formed by fracturing of shale and by interbedded coarser clastics on structures are com- Southern Ute Indian Reservation 200ft mon. UT CO Juana Lopez AZ NM A' Exploration status and resource potential: Most of the larger dis- coveries, such as Verde and Puerto Chiquito, were made prior to 1970, but directional drilling along the flanks of some of the poorly A n Limestone 0 explored structures could result in renewed interest in this play. Mancos Fractured Top of Greenhor 0 10mi Shale Play Characteristics of Mancos Fractured Shale Play Figure SU-53 Subsurface stratigraphic cross section across the central San Juan Basin. Dashed lines are time marker bentonites or calcareous silty zones. Approximate location of section is labeled in Figure SU-51 (modified after Molenaar, The Mancos Fractured Shale play produces oil from fractures in the 1973 and Tillman, 1985). Niobrara-Carlile age clastic sediments (Fig. SU-53) which represent Figure SU-51 Location of the Mancos Fractured Shale Play (modified after the first regressive wedge in the San Juan Basin (Gorhman et Gautier et al., 1996). al.,1978; DuChene, 1989). These sediments have little or no effec- tive porosity and permeability except that associated with fractures.

The units of interest to oil exploration are the basal Niobrara (lower 0 0.5 1 mile Tocito Sandstone), Niobrara-Carlile unconformity (upper Carlile N Shale-Tocito Sandstone contact), and Carlile Shale/siltstone interval 7000 6000 above the Juana Lopez (Fig. S-53). The Niobrara-Carlile stage is lat- 5000 erally consistent with respect to siltstone content, cement content, 3000 1000 2000 4000 0 4000 and other observable stratigraphic phenomenon. -1000 The Hogback Monocline (Fig. SU-52) is the structural feature associated with the fractures in the Mancos Shale. It is located in the Hogback northwest flank of the San Juan Basin, southwest part of the Southern Figure SU-52 Structure line Monocline Ute Indian Reservation. It has a dip as great as 60 and has up to contour map of the Dakota 8,000 feet of structural relief. Fractures are mostly associated with Sandstone showing the 1000 3000 k Monoc -1000 areas of maximum flexure and where anticlines and synclines inter- Hogback Monocline and 0 Southern Ute Indian Reservation associated anticlines and 2000 sect the monocline. The fractures are best developed parallel to the -1500 synclines (modified after Hogbac trend of the fold. Fracture apertures range from 1 ¾ inches to hair- Anderson, 1995). line cracks.

SOUTHERN UTE INDIAN RESERVATION UNCONVENTIONAL PLAY TYPE: Mancos Fractured Shale Play 21 COLORADO Analog Fields in and near Reservation (*) denotes that field lies within the reservation boundaries

La Plata Gallup (Figs. SU-54 & SU-55)

Location of discovery well: SE, SW, sec 5, T31N, R13W (1959) Producing formation: Cretaceous Mancos Shale La Plata Gallup Field Type of trap: Stratigraphic, Fractured Shale Benson-Montin-Greer Drlg. Corp. Number of producing wells: 4 (1978) Structural Contour Map La Plata Mancos No. P-31 Initial production: 241 BOD SE 1/4 sec. 31-32N-13W Cumulative Production: 635,144 BO and 539, 607 MCGG (1994) R 13 W Gamma Ray-Induction Oil characteristics: Sweet, yellow-green, 38 API gravity Elev-RKB 6075 Type of drive: Combination gravity drainage and solution gas Average net pay: uncertain, probably less than 30 feet Porosity: uncertain, probably on the order of 1% +2000 +4100 21 +4200 +400020 22 Permeability: Unknown Contoured on Electric Log 19 +3000 Marker "E" Within the A Verde Gallup Mancos Shale T (Fig SU-54) 32 contour intervals

N 2700 Location of discovery well: SE, SE, sec 14, T31N R15W (1955) 1000' B Producing formation: Fractured interval in Cretaceous "Gallup" 100' 27 sandstone (basal Niobrara age rocks) Boundary of La Plata 30 29 28 Type of trap: Fractured shale, structural Gallup Pool Number of producing wells: 27 (1978) Initial production: 180 BOD Cumulative Production: 7,963,004 BO and 174,956 MCFG (1994) R 14 W C Oil characteristics: 38-42 API gravity Type of drive: Gravity drainage 35 32 33 Average net pay: Variable 34 2800 36 31 Porosity: Fracture Permeability: Unlimited

Chromo (poor historical data)

Ref: Fassett, 1983, 1978; Wells and Lay, 1996 2 1 6 5 4 3

R15W R1W T

D 2900 31 N +4200 11 12 7 +4100 8 9 10 0 E Chromo T33N Southern Ute Indian Reservation Field -200

CO -100 NM +4000 +3000 +1000 Dec. 1977 La Plata +2000 Gallup Verde Figure SU-55 Structure contour map and type log for the La Plata Gallup field. Structure contour lines are drawn on the "E" marker which is the top of the Niobrara Stage, which Gallup Horseshoe generally produces highest electrical resistivities in the Mancos Shale. Contour interval is 100 feet. (modified after Greer, 1978). R16W T30N R1W R1E Figure SU-54 Location of oil field discovery wells for fields producing from the Mancos Fractured Shale Play.

SOUTHERN UTE INDIAN RESERVATION UNCONVENTIONAL PLAY: Mancos Fractured Shale Play 22 COLORADO 23 R1W R1E Navajo City Chacra : Central Basin Mesaverde Gas Play : Central Basin Mesaverde Blanco Mesaverde Animas Chacra Southern Ute Indian Reservation Ignacio Blanco Mesaverde

Red Mesa (see Fig SU-58) Flora Vista Mesaverde

T30N UNCONVENTIONAL PLAY TYPE UNCONVENTIONAL PLAY NM T33N CO Animas Chacra R16W Location of discovery wells for fields producing from for wells Figure SU-57. Location of discovery Gas Play. Basin Mesaverde Central Navajo City Chacra Navajo Flora Vista Mesaverde SE, SW, sec 15, T32N, R11W (1952) T32N, 15, sec SE, SW, Mesaverde Cretaceous trapping basinal hydrodynamic Stratigraphic, 825 (1992) 1,710 MCFGD B Condensate (1992) 625,860,995 MCFG, 257,988 BTU 970-1040 range dry reservoirGas expansion, gas 20 - 150 feet 9.1% ave. fractures natural enhanced by 0.02-0.5 mD intergranular, T31N, R10W sec 6, NW, NW, (1975) Gas expansion 42 feet 4-6% Unknown T30N, R12W (1961) sec 22, SW, SW, Cretaceous Cliff House Sandstone Stratigraphic 9 (19994) 5,988 MCFGD 20,267,279 MCFG and 96,159 B Condensate BTU 1,252 Solution Gas 18.5 feet 14-17% 2-3 md T30N, R8W (1974) sec 35, NW, SW, Sandstone tongue of Cliff House "Chacra" Shale above Lewis Cretaceous Chacra: sandstone (tongue of La Ventana Member, Cliff House ss) Member, Ventana sandstone (tongue of La Cretaceous Chacra: Stratigraphic 1 (1994) 3,300 MCFG 8,086,233 MCFG and 1,988 B Condensate Unknown Fractures Natural 2 (1994) 3,433 MCFGD 9,862,944 MCFG (1994) Unknown Gas expansion 15 feet fracture 3-4% matrix, probably unknown Fracture, T 34 N T 33 N T 32 N * Blanco Ignacio *Red Mesa (poor historical data)

R 6 (*) denotes field lies within the reservation field lies within the (*) denotes boundaries) Analog Fields in and near Reservation near Reservation Fields in and Analog W

R

7 W

1600

1500 1800 1900 1700

1400 Type of drive: of drive: Type net pay: Average Porosity: Permeability: well: Location of discovery Producing formation: of trap: Type Number of producing wells: Initial production: Production: Cumulative Gas characteristics: of drive: Type net pay: Average Porosity: Permeability: well: Location of discovery Producing formation: Location of discovery well: well: discovery Location of Producing formation: of trap: Type Number of producing wells: Initial production: Production: Cumulative Gas characteristics: of drive: Type net pay: Average Porosity: Permeability: well: Location of discovery Producing formation: of trap: Type Number of producing wells: Initial production: Production: Cumulative Gas characteristics: of trap: Type Number of producing wells: Initial production: Production: Cumulative Gas characteristics: of drive: Type net pay: Average Porosity: Permeability: R 8

W 1800

R

9 1900 W

Colorado

New Mexico

R 10 W 2000

1900 1800 1800 The Blanco Me- The Blanco

R 11 W Figure SU-58 Structure contour map and log pool of the Ignacio Blanco the Mesaverde for on Structure contours are drawn Gas field. contour zone, transition the Mesaverde (modified after Bowman, interval is 100 feet 1978). Datum: Sea Level Southern Ute Indian Reservation T/Menefee Mesaverde Transition Zone T/Point Lookout IND 4400 4600 4800 5000 5200 NWP Colorado IP-5,521 MCFD GR CAOF-15,818 MCFD Contour Interval=100' Mesaverde Pool SE 1/4 25-34N-10W NM CO La Plata Co., Colorado Bondad 34-10 #4-25 Bondad-Ignacio Field La Plata & Archuleta Co's. UT AZ Location of the Central Basin Mesaverde Gas Play Play Gas Basin Mesaverde Figure SU-56. Location of the Central (modified after Gautier et al., 1996). Contoured on the Mesaverde Transition Zone Exploration status and resource potential: status and resource Exploration and the Ignacio completed in 1927, well was discovery field saverde in 1952. completed well was discovery field Blanco Mesaverde 1,000,000 acres, more than cover adjacent fields these two Areally, and have the central part of the San Juan Basin, encompass much of conden- BCFG and more than 30 MMB of produced almost 7,000 Most of half of their estimated total recovery. sate, approximately range in areal size from 2,000 to 10,000 the recent gas discoveries of from 10 to 35 BCFG. estimated total recoveries acres and have

(USGS 2209) (USGS 2209) General Characteristics General The carbon composition (C1/C1-5) of 0.99-0.79 and The carbon composition (C1/C1-5) of 0.99-0.79

Principal gas reservoirs productive in the Mesaverde in the Mesaverde productive Principal gas reservoirs Trapping mechanisms for the largest fields in the central part fields mechanisms for the largest Trapping

Central Basin Mesaverde Gas Play Gas Play Basin Mesaverde Central interval are the Point Lookout and Cliff House marine sandstones. and Cliff are the Point Lookout interval gas are produced from thin, non-associated Smaller amounts of dry, and thin coal beds of the Me- lenticular channel sandstone reservoirs nefee. quality tight, and reservoir Much of this play is designated as the Blanco Together, of fracturing. depends mostly on the degree half of the account for almost and Ignacio Blanco fields Mesaverde production from the San total non-associated gas and condensate Juan Basin. about 10 per- averages porosity fields two these Within pay thickness is 20-200 cent and permeability less than 2 md; total ft. porosities ranging from 14 to 28 have fields Smaller Mesaverde md, with 6-25 ft of pay percent and permeabilities from 2 to 400 thickness. Traps: Traps: Source rocks: rocks: Source Reservoirs: The unconventional continuous-type Central Basin Mesaverde Gas Gas Central Basin Mesaverde continuous-type The unconventional stratigraphic rises in associated with buildups Play is in sandstone Sandstones House and Cliff Point Lookout the Upper Cretaceous (Gautier et al, 1996). San in the gas-producing interval The major comprises the Group Cretaceous Mesaverde Juan Basin , the Upper Sandstone, the nonmarine Menefee marine Point Lookout regressive To- House Sandstone. Cliff marine and the transgressive Formation, ft , of ranges from about 500 to 2,500 interval tal thickness of the is sandstone. which 20-50 percent en- is interval The Mesaverde and the Mancos Shale is beneath the interval closed by marine shale; Shale above. the Lewis of the San Juan Basin are not well understood. In both of these and Ignacio Blanco, hydrodynamic Mesaverde the Blanco fields, parts of the to contain gas in structurally lower forces are believed such as cementation and swelling clays may other factors basin, but also play a role. Production depths are most commonly from 4,000 to 5,300 ft. grained Updip pinchouts of marine sandstone into finer paludal or marine sediments account for almost all of the strati- graphic traps with a shale or coal seal. isotopic carbon (d13C1) range of -33.4 to -46.7 per mil of the non- isotopic carbon (d13C1) range of -33.4 rocks including coal and associated gas suggest a mixture of source (Rice, 1988). carbonaceous shale in the Menefee Formation and migration: In the central part of the basin, the Mancos Timing Shale entered the thermal zone of oil generation in the Eocene and of gas generation in the Oligocene. also en- The Menefee Formation tered the gas generation zone in the Oligocene. Because basin con- have updip migration would to that of today, similar was figuration been toward the south. Migration was impeded by hydrodynamic Migration was the south. been toward the central basin, as well as by the deposi- pressures directed toward of Menefee tion of authigenic swelling clays due to dewatering coals. COLORADO SOUTHERN UTE INDIAN RESERVATION SOUTHERN UTE INDIAN RESERVATION Pictured Cliffs Gas Play traps and excellent source rocks are present in the deeper parts of the A' Figure SU-60. T DURANGO (USGS 2211) basin, but low permeabilities due to authigenic illite-smectite clay 35 Structure contour map N have thus far limited production. of the Pictured Cliffs Southern Ute Indian Reservation General Characteristics Sandstone and major Monocline T Ignacio structural features 33 The Pictured Cliffs unconventional, continuous-type play is defined Characteristics of the Pictured Cliffs Gas Play N Hogback

Archuleta Arch 6400

7200 (modified after Kelso MONTEZUMA CO. Anticline 5600 UT CO LA PLATA CO. CO ARCHULETA4800 CO. primarily by gas production from stratigraphic traps in sandstone res- on the Southern Ute Indian Reservation 4000 and Wicks, 1988). AZ NM SAN JUAN CO. NM 3600 ervoirs enclosed in shale or coal at the top of the Upper Cretaceous Numerous studies have focused on the Pictured Cliffs Sandstone in T 31 Pictured Cliffs Sandstone and is confined to the central part of the ba- the Southern Ute Indian Reservation in the past ten years. For this N

sin (Gautier et al., 1996). Thicker shoreline sandstones produced by reason, the following should be considered an extremely brief over- FRUITLAND FORMATION stillstands, or brief reversals in the regression of the Cretaceous sea to view. OUTCROP FARMINGTON T 3200 29 the northeast, have been the most productive. The Pictured Cliffs is The Pictured Cliffs Sandstone represents a littoral deposit in a N the uppermost regressive marine sandstone in the San Juan Basin. It wave dominated system during the final northeasterly regression of 3600 T ranges in thickness from 0 to 400 ft and is conformable with both the the Cretaceous sea. The Lewis Shale is stratigraphically below and 27 4000 N underlying marine Lewis Shale and the overlying nonmarine Fruit- intertongues with the Pictured Cliffs (Fig. SU-61). In recent years, A Uplift Nacimiento land Formation. Pictured Cliffs gas development has shifted from a depleted structural 4400 T 25 Reservoirs: Reservoir quality is determined to a large extent by the accumulation to a stratigraphically trapped accumulation (Harr, 1988, N 4800

abundance of authigenic clay. Cementing material averages 60 per- and Hoppe, 1992). Two interpretations for high gas production exist 5200

T in the literature. The first is that gas production is controlled by local RIO ARRIEA CO. cent calcite, 30 percent clay, and 10 percent silica. Average porosity 23 AN CO. 5600 is about 15 percent and permeability averages 5.5 md, although many sandstone lenticularity and permeability barriers (shales) developed N

R19W R17W R15W R13W SAN JU field reservoirs have permeabilities of less than 1 md. Pay thickness- along the shore-side slope of coastal barriers. Higher yield wells are Charo Slope 6000 T attributed to individual thicker sandstone lenses which are least sha- 21 CUBA es range from 5 to 150 ft but typically are less than 40 ft. Reservoir CO. SANDOVAL Major Structural Features and Structure N 6400 quality improves southward from the deepest parts of the basin due to ley. The second interpretation is that the Pictured Cliffs is character- MC KINLEY CO. Contour Map on the Pictured Cliffs Sandstone secondary diagenetic effects. ized as a low-permeability, gas saturated reservoir with production Contour Interval : 400 ft T dependent on fractures. Fractures play a crucial role in production. Datum: Sea Level 19 Source rocks: The source of gas was probably marine shale of the N underlying Lewis Shale and nonmarine shale of the Fruitland Forma- The highest producing wells in the Pictured Cliffs show communica- SAN JUAN BASIN COLORADO

tion between them, which is explained by fractures. For this reason, T . tion. The gas is nonassociated and contains very little condensate COLORADO AND NEW MEXICO STUDY 17 AREA fracture identification is important in identifying new reservoirs. 0 10 20 Miles N (0.006 gal/MCFG). It has a carbon composition (C1/C1-5) of 0.85- CO VAL

Landsat imagery (Fig. SU-62) and multi-component 3-D seismic are NEW 0.95 and an isotopic carbon (d13C1) range of -43.5 to -38.5 per mil MEXICO SANDO being used to interpret fracture orientations and frequencies in the N T (Rice, 1988). 1987 15 N Timing and migration: Gas generation was probably at a maximum subsurface. during the late Oligocene and the Miocene. Up-dip gas migration R11W R9W R7W R5W R2W R1W was predominantly toward the southwest because the basin configu- ration was similar to that of today. Figure SU-61. - -> A A' Traps: Stratigraphic traps resulting from landward pinchout of near- Southwest-northeast SW 9 shore and foreshore marine sandstone bodies into finer grained silty, trending stratigraphic FEET NE cross section showing 1500 shaly, and coaly facies of the Fruitland Formation (especially in the Animas For areas of stratigraphic rises) contain most of the hydrocarbons. Seals the northeast mation and y stratigraphic rise of 1000 Ojo Alamo Sandstoneks and7 8 ounger rocks are formed by finer grained back-beach and paludal sediments into younger6 roc the Pictured Cliffs 5 which marine sandstones intertongue throughout most of the central Sandstone and 500 Upper shale member andFarmington OUTCR part of the basin. The Pictured Cliffs Sandstone is sealed off from associated rocks. 4 Southern Ute Indian Reservation Sandstone Member of Kirtland Shale UT CO Section is located in 5 10 15 MILES other underlying Upper Cretaceous reservoirs by the Lewis Shale. 0 3 The Pictured Cliffs crops out around the perimeter of the central part AZ NM Fig. SU-60 (modified VERTICAL EXAGGERATION ABOUT X 53 OP after Fassett, 1988). of the San Juan Basin and is present at depths of as much as 4,300 ft. Kirtland Shale 2 of Most production has been from depths of 1,000-3,000 ft. shale member Lower Exploration status and resource potential: Gas was discovered in OP Fruitland Formation 1 the play in 1927 at the Blanco and Fulcher Kutz fields of northwest Surface OUTCR casing Pictured Cliffs Sandstone New Mexico. Most Pictured Cliffs fields were discovered before 1954, and only nine relatively small fields have come into production Lewis Shale since then. Discoveries since 1954 average about 11 BCFG estimat- Huerfanito Bentonite Bed A Datum A' ed ultimate recovery. A large quantity of gas is held in tight sand- Figure SU-59. Location of the Pictured Cliffs Gas Play (modified after stone reservoirs north of the currently producing areas. Stratigraphic Gautier et al., 1996)

SOUTHERN UTE INDIAN RESERVATION UNCONVENTIONAL PLAY TYPE: Pictured Cliffs Gas Play 24 COLORADO R1W Analog Fields within and near Reservation R15W (*) denotes field lies within the reservation boundaries) Figure SU-63. Location of *Ignacio Blanco (see Figs. 63 and 64) discovery well for fields that Location of discovery well: NE ¼, NW ¼, sec 7, T33N, R7W (1951) produce from the Pictured Cliffs ·Producing formation: Cretaceous Pictured Cliffs Sandstone Gas Play in and near the Southern ·Type of trap: Structural / Stratigraphic Ute Indian Reservation. Ignacio Blanco ·Number of producing wells: 115 (1986) ·Initial Production: 2,200 MCFGD T33N Southern Ute Indian Reservation ·Cumulative Production: 26,750,352 MCFG (1986) CO ·Gas characteristics: 990 BTU NM Albino Pictured Cliffs ·Type of drive: Solution gas 108.0 107 W + + + ·Average net pay: 16-205 feet, 70 feet average Aztec Pictured Cliffs ·Porosity: 4.4% Twin Mounds Blanco Pictured Fruitland/Pictured Cliffs Contact ·Permeability: 0 - 1500 mD R16W T30NPictured Cliffs Blanco Pictured Cliffs Cliffs East R1W R1E

Albino Pictured Cliffs ·Location of discovery well: SE ¼, SW ¼, sec 26, T32N, R8W (1974) ·Producing formation: Cretaceous Pictured Cliffs Sandstone R10W R9W R8W R7W R6W R5W ·Type of trap: Stratigraphic T35N Southern Ute Indian Reservation T35N ·Number of producing wells: 15 (1994) +1500 T34N T34N CO ·Initial Production: 556 MCFGD +1000 37 N + R11W +2000 NM ·Cumulative Production: 7,260,895 MCFG (1994) +1500 +1500 Southern Ute Indian +500 ·Gas characteristics: 1,074 BTU Reservation +1000 T34N +1000 T34N ·Type of drive: Gas Expansion Boundary +1000 +900 ·Average net pay: 40 feet average R12W R5W +300

·Porosity: 12% +1000 +600 +1000 ·Permeability: NA +900 T33N +900 T33N +900

Aztec Pictured Cliffs +800 +300 +700 +400 +500 ·Location of discovery well: SE ¼, SW ¼, sec 10, T30N, R11W (1951) +600 +900 +2000 ·Producing formation: Cretaceous Pictured Cliffs Sandstone T32N T32N +1000 +800 ·Type of trap: Stratigraphic +900 +500 ·Number of producing wells: 559 (1994) T32N +500 T32N ·Initial Production: 180 MCFGD R12W R11W R10W R9W R8W R7W R6W ·Cumulative Production: 340,024,535 MCFG (1994) ·Gas characteristics: 1,169 BTU ARCO ·Type of drive: Gas expansion with water encroachment SOUTHERN UTE 32-9 NO. 1-2 sw sw sec. 1, T32N, R9W Kirtland Shale ·Average net pay: 40 feet average 0 6 La Plata County, Colorado 3600 ·Porosity: 15% miles COMP. 1-26-78 IP-3700 MCFGD ·Permeability: 545 mD CUM DEC 86-442,917 MCFG 36 N + 0 10 20 30 mi Twin Mounds Pictured Cliffs 3700

0 20 40 km Location of discovery well: SE ¼, SW ¼, sec 33, T30N, R14W (1951) Producing formation: Cretaceous Pictured Cliffs Sandstone Fruitland Type of trap: Sratigraphic, up-dip gradation sand to shale 3800 Formation Figure SU-62. Landsat lineaments in the San Juan Basin (modified after Number of producing wells: 7 (1994) IGNACIO BLANCO GAS FIELD Baumgardner, 1994). Initial Production: 1,875 MCFGD NORTHERN SAN JUAN BASIN, COLORADO Cumulative Production: 2,288,169 MCFG (1986) 3900 Gas characteristics: 1,153 BTU PICTURED CLIFFS RESERVOIR Type of drive: Volumetric gas reservoir PRODUCING WELLS Average net pay: 10 feet average PERF STRUCTURE: TOP UPPER MANCOS SHALE 4000 Porosity: 24% CONTOUR INTERVAL=100 FEET Pictured Cliffs Permeability: 65 mD Sandstone

(Fassett, 1983, 1978; Wells and Lay, 1996) 4100 GR IND T.D. 4125 DRL Figure SU-64. Structure contour map and log for the Ignacio Blanco Gas Field (modified after Harr, 1988).

SOUTHERN UTE INDIAN RESERVATION UNCONVENTIONAL PLAY TYPE: Pictured Cliffs Gas Play 25 COLORADO COAL BED GAS PLAYS ductive year ranges from 30 to 300 MCFPD. The potential for un- Overpressured Play discovered coal-bed gas in this play is good to fair. Similar to the (USGS 2250) Overpressured Play, extensive drilling and production (Basin Fruit- Underpressured Discharge Play land Coal-Bed Gas Field) have taken place in this play, and the re- (USGS 2252) maining potential for reserves is mainly at shallower depths (less Underpressured Play than 1,500 feet) in the southwestern part of the play. (USGS 2253) The San Juan-Underpressured play (2253) is in the eastern part of the basin where groundwater flow is sluggish. The produced wa- General Characteristics ters are a NaCl type and similar to seawater. Coal beds are generally On the basis of hydrology, pressure regime, reservoir properties, and thin and gas content is low, particularly in the eastern part. Minor hydrocarbon composition, three plays are identified for the Fruitland production has been established and rates are low (average annual coal-bed gas: (1) San Juan-Overpressured Play, (2) San Juan-Under- production in the range of 1 to 3 MMCF) with little or no water pro- pressured Discharge Play, and (3) San Juan-Underpressured Play duction. Depths of burial (500-4,000 feet) and coal rank (subbitumi- UT CO Southern Ute Indian Reservation (Gautier et al., 1996). nous to medium-volatile bituminous) are variable and generally in- The San Juan-Overpressured Play (2250) is in the north-central crease to the north. The potential for additional reserves from this AZ NM part of the basin and north of the structural hingeline where recharge play is only fair because of underpressuring and low permeability. of relatively fresh water takes place. The coals are generally thick (greater than 10 feet) and laterally extensive in northwest-trending Underpressured bands. The coals are generally of high rank (as much as medium- Discharge Play volatile bituminous), have high gas contents, and are characterized by high formation pressures (greater than 0.5 psi/ft). The coal-bed gases are relatively dry (heavier hydrocarbons less than 3 percent) and contain significant amounts of CO2 (3-12 percent). Although depths of burial extend to 4,200 feet, the Fruitland Coal in a large Figure SU-66. Location of the Underpressured Discharge Play (modified after part of the play is at depths of less than 3,000 feet. Within this play Gautier et al., 1996). is the very productive "Fairway" Trend. The average daily gas pro- duction for wells in this play during their most productive year rang- es from less than 30 MCF/D to more than 3,000 MCF/D, and the highest rates were in the "Fairway" Trend. Because of recharge of fresh water on the north margin, most wells produce water at rates as high as 2,000 bbl/D and must be dewatered to initiate desorption and production. Because of the high productive capacity of wells in this play, the prime areas have been explored and developed (Cedar Hills, UT CO Southern Ute Indian Reservation Ignacio-Blanco, and Basin Fruitland Coal Fields). The potential for additional reserves from this play is considered to be good; however, AZ NM the areal extent of this potential is limited because of previous devel- Overpressured Play opment. The San Juan-Underpressured Discharge Play (2252) is south of UT CO Southern Ute Indian Reservation the structural hingeline in the southwest part of the basin where the coal beds are underpressured (0.3 to 0.4 psi/ft). The area is charac- AZ NM terized by regional groundwater convergence and discharge. The groundwater is a NaCl type and has a higher chloride content than Underpressured Play that of the overpressured play. Coals may be as thick as 10 feet and the thickest coals are in northeast trends. Compared to the Overpres- Figure SU-65. Location of the Overpressured Play (modified after Gautier et al., sured Play, coal rank is lower (high-volatile B bituminous and lower) 1996). and gas contents are lower. The gas is chemically wet (heavier hy- drocarbons generally more than 5 percent) and contains less than 1.5 percent CO2. During early months of production, the coals of high- volatile B bituminous rank produce some waxy oil. Depths of burial Figure SU-67. Location of the Underpressured Play (modified after Gautier et al., are less than 3,000 feet, and production is commonly water free. The 1996). average daily production of wells in this play during their most pro-

SOUTHERN UTE INDIAN RESERVATION CONVENTIONAL PLAY TYPE: Overpressured Play/Underpressured Discharge Play/Underpressured Play 26 COLORADO Coal-Bed Gas Plays two areas is rather abrupt and coincides with the structural hingeline. tween low chloride, NaHCO3-type water and high chloride NaCl- “Fairway,” located north of the structural hingeline. Cavity wells in the In the southern part, the gases are generally wet (heavier hydrocar- type water coincides with the structural hingeline. Water production “Fairway” are successful because of artesian overpressuring and high In the San Juan Basin, significant resources of both coal and coalbed bons generally greater than 6 percent) with minor amounts of CO2 rates for individual wells are highly variable and range from essen- permeability; open-hole cavity completions have not been successful in gas are in the Upper Cretaceous Fruitland Formation (Rice and Finn, (generally less than 1 percent). Waxy oil is produced in association tially nothing to more than 2,000 barrels per day. The production other basins. 1996) . The occurrence, thickness, and geometry of Fruitland coal with wet gases in this part. In contrast, gases in the north part are rates are strongly controlled by hydrodynamics, and the highest rates The first coalbed gas well (Cahn No. 1) was drilled in the New deposits are strongly influenced by depositional environment. Coal dry (heavier hydrocarbons generally less than 3 percent) but contain are north of the hingeline and along the northern margin. Most of the Mexico part of the basin in the late 1970’s. The well is part of the Ce- deposits resulted from peat that accumulated on sandstone platforms significant amounts of CO2 (generally greater than 6 percent). On water is currently being injected into deep wells. However, the dis- dar Hills coal field. Most of the production in New Mexico is assigned of the underlying Pictured Cliffs Sandstone, which were deposited the basis of chemical and isotopic composition, the hydrocarbon gas- posal capacity is rapidly being approached and alternate, cost-effec- to the Basin Fruitland coal field, and all the production in Colorado is along the coast of a northeast-prograding shoreline. Individual coal es are interpreted to be mainly thermogenic in origin. The heavier tive methods of disposal will be required. assigned to the Ignacio-Blanco coal field. The reserves in the basin as beds are as much as 40 ft thick. The greatest net coal thickness, up hydrocarbon gases and oils, which are restricted to coals of high-vol- The Fruitland coal beds are both abnormally pressured and un- of 1993 are about 7.8 TCF, which represents about 70 percent of the to 100 ft, is in a northwest-trending belt in the northern part of the atile B bituminous and lower ranks, were probably generated from derpressured relative to fresh-water hydrostatic pressure. Overpres- coalbed gas reserves in the country. basin where thick coal deposits occur in both northwest- and north- hydrogen-rich coals. In the northern part of the basin, active ground- suring occurs in the north-central part of the basin and coincides with The San Juan Basin has had major gas pipelines to southern Cali- east-trending deposits, with the thickest deposits in the northwest- water flow has probably led, relatively recently, to intensified micro- the area of relatively fresh water. The overpressuring is interpreted to fornia since the 1950’s, when gas was first produced from Cretaceous trend. In the northwest-trend, individual coal beds average more bial activity resulting in aerobic consumption of the heavier hydro- be artesian in origin as evidenced by the flowing artesian coalbed gas sandstones. With the rapid development of coalbed gas, pipeline ca- than 9 ft in thickness, which resulted from standstills in the Pictured carbons and mixing of biogenic methane-rich gas. Isotopic data sug- wells. However, most of the basin is underpressured. The transition pacity was insufficient in the late 1980’s. Since 1990, major expansion Cliffs Sandstone shoreline. Average thickness of coal beds in the gest that the large amounts of CO2 in the north part of the basin are from overpressured to underpressured is abrupt and takes place along projects have resulted in increased capacity for transmitting the gas to northeast-trend is 6 ft. They occur in floodplain facies between also the result of recent bacterial activity the structural hingeline. interstate markets. channel-fill sandstone deposits. Depths of burial for the Fruitland The San Juan Basin is a strongly asymmetric basin with a gently Gas contents in the San Juan Basin are highly variable and range coal beds are as much as 4,200 ft in the northeastern part of the ba- dipping southern flank and steeply dipping northern flank. It has from less than 100 to more than 800 Scf/t. As expected, there is a sin. two axes in the northeastern part of the basin, which are separated by general relation between gas content, depth, and rank. However, the Coal beds in the Upper Cretaceous Menefee Formation are an the Ignacio Anticline. A structural hingeline has been interpreted to gas content also strongly correlates with the pressure regime. In additional target for gas. The Menefee is older and deeper than the occur where the gently dipping southern monocline meets the basin dealing with coals of similar rank, the highest gas contents are usual- Fruitland and is in the middle part of the Mesaverde Group. Al- floor. This hingeline is probably a zone of northwest trending, en- ly reported from the overpressured north-central part of the basin. though as much as 35 net ft of coal occur in the Menefee, the coals echelon normal faults and divides the basin into two distinct areas On the basis of resources and a range of gas contents, in-place are generally thinner, more discontinuous, and dispersed over a relative to coalbed gas productivity. coalbed gas resources of the Fruitland Formation are estimated to be greater stratigraphic interval than those of the overlying Fruitland The Colorado-New Mexico border roughly marks the division of about 50 TCF. An additional 38 TCF have been estimated for the Formation. The Menefee coals are as deep as 6,500 ft. the basin into two areas of distinctly different face-cleat orientations. Menefee coal beds resulting in a total of 88 TCF for the basin. Across the central basin, the rank of Fruitland coal increases North of the border the cleats are oriented northwestward; however, New Mexico ranked 14th among the States in 1991 for the pro- northeastward from subbituminous C to medium-volatile bitumi- south of the border they are oriented northward or northeastward. duction of coal. Most of this coal was mined on the surface from the nous. Coal rank generally conforms with the structural configura- Along the State border, interference of the two sets may result in in- Fruitland along the western flank of the basin. The New Mexico tion of the basin and abruptly decreases along the steeply dipping creased permeability, which has led to the success of vertical open- counties of San Juan and McKinley, located on the west flank of the north flank. Rank trends for Menefee coals are similar, but some- hole cavity completions. Increased permeability may also result basin, were ranked 7th and 10th in the nation in terms of production what higher because of greater burial depth. Present-day depths of from compaction-induced fractures in areas where the Fruitland coal from surface mining. Some coal is also mined in the Colorado part burial do not coincide with the maximum levels of thermal maturity beds overlie upper Pictured Cliffs sandstone tongues. In addition, of the basin. Because the coal in the basin is mostly mined on the in the northern part of the basin. This is partly the result of signifi- compaction-induced fractures may be present where coal beds split surface, methane emissions are minor. cant uplift and erosion that has taken place since about 10 Ma. and interfinger with fluvial channel-sandstones. In the Cedar Hill The San Juan Basin has been the most productive coalbed gas However, maximum depth of burial and present-day heat flow can- coal field area of northern New Mexico, multicomponent 3D seismic basin in the United States since 1988. In 1992, more than 436 BCF not account for the high rank present at the north end of the basin. surveys indicate that movement on basement-controlled faults with of coalbed gas were produced from about 2,000 wells. In 1993, more In addition to maximum burial depths, this high rank is interpreted to strike-slip displacement has opened natural fractures in the coal. than 480 BCF were produced from about 1980 wells in only the New be the result of (1) convective heat transfer associated with a deeply Fruitland coal beds are major aquifers in the San Juan Basin. In Mexico part of the basin. Most of the coalbed gas wells in the basin buried heat source located directly below the northern part of the ba- the northern part of the basin, they are commonly thick, well cleated, have been drilled since 1987 and the largest number was completed sin, and (or) (2) the circulation of relatively hot fluids into the basin and more permeable than the adjacent sandstones that serve as aqui- in 1990. Although the Black Warrior Basin has the largest number from a heat source located in the vicinity of the San Juan Mountains tards. Recharge is mainly along the wet, northern margin of the ba- of producing wells, more than four times as much coalbed gas was to the north. Thermogenic gases were probably generated in the sin in the foothills of the San Juan Mountains with limited recharge produced in the San Juan Basin in 1992 (436 BCF versus 92 BCF). coals during time of maximum heat flow and (or) depth of burial in along the other margins. A sharp steepening of the potentiometric Production rates for individual wells are highly variable and range Tertiary time. surface occurs along the structural hingeline and divides the basin from 50 to 15,000 MCFGPD. About one-third of the total producing Produced Fruitland coalbed gases are variable in their composi- into two hydrologic provinces. This steepening indicates an area of wells are vertical open-hole cavity wells, which accounted for about tion. Although methane is the major component, significant reduced permeability and is a no-flow boundary. 75 percent of the gas production in 1992. These cavity wells com- amounts of heavier hydrocarbon gases (as much as 23 percent), CO2 Groundwater movement and associated reservoir characteristics monly produce 10 times more gas than those completed by hydraulic (as much as 13 percent), and nitrogen (as much as 11 percent) are al- can be tracked by water composition, in particular the chloride con- fracturing. However, successful, open-hole cavity completions are so present. The producing part of the basin can be divided into two tent. Lobes of relatively fresh, low-chloride water extend into the generally restricted to a northwest-trending area referred to as the areas based on coalbed gas composition. The boundary between the basin from the northern margin. The hydrochemical boundary be-

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