Successful Exploratory Wells Research Articles

Upon Further Consideration, US Gas Reserves Look Bigger

A second look at the size of US shale formations is revealing they hold far more natural gas, and pushed a new name up near the top of the list: the Mancos Shale. A recent reassessment of the formation in western Colorado concluded it holds 66 Tcf of shale gas that could be produced using current technology, making it second only to the prolific Marcellus Formation for unconventional gas in the US. This elevates the profile of the formation, which the US Geological Survey (USGS) had previously estimated at 1.6 Tcf in 2003. The agency also recently upped its estimate for the Barnett Shale, doubling it to 53 Tcf. “We reassessed the Mancos Shale in the Piceance Basin as part of a broader effort to reassess priority onshore US continuous oil and gas accumulations,” said Sarah Hawkins, a USGS geologist who was the lead author of the study. “In the last decade, new drilling in the Mancos Shale provided additional geologic data and required a revision of our previous assessment of technically recoverable, undiscovered oil and gas.” Based on a growing body of data, the USGS is working on assessments of two Texas plays, the Wolfcamp in the Midland Basin, and the Eagle Ford Shale; and one in Colorado, the Niobrara in the Denver Basin. For those drilling into the Mancos, the USGS evaluation confirms what they have been seeing. “There has been drilling for the last 20 years and there is decades worth of drilling location left,” said David Ludlam, executive director of the West Slope Colorado Oil and Gas Association, who said the gas potential may well exceed 100 Tcf. He said operators working there have dozens of successful exploratory wells in shale, but the current gas market does not justify development drilling. The gas sands there are commonly developed using slanted vertical wells from pad sites with multiple wells. The USGS used data from 2,000 wells drilled since its last evaluation, as well as field work and research core analysis, to divide the formation into units with similar geologic and well production characteristics, Hawkins said. That work led to an estimate of technically recoverable reserves for the Mancos ranging from 34 Tcf to 112 Tcf, with a mean of 66 Tcf. Glowing assessments of the gas in the ground are not fueling the sort of activity that transformed the Marcellus. Recently there were no rigs drilling in the Barnett, and 12 of the 16 wells working in Colorado were in the DJ Basin in the eastern part of the state, according to data by Energent Group, a provider of shale data.

New Exploration Targets in Malaysia: Deep Sandstone Reservoirs in Malay Basin and Turbidites in Sabah Basin: ABSTRACT

Much of the production in Malaysia is from middle to upper Miocene sandstones and carbonates in three main basins: Malay, Sarawak (Its three subbasins-Central Luconia, Balingian and Baram), and Sabah. Fifteen fields produce an average of 630,000 bopd and 3.0 bcfgpd. More than 4.0 billion barrels of oil and 20 tcf of gas have been produced, and reserves are 4.2 billion barrels of oil and 90 tcf. Oil production will decline within the next 1 0 years unless new discoveries are made and/or improved oil recovery methods introduced, but gas production of 5 tcf, expected after the turn of the century, can be sustained for several decades. Successful exploratory wells continue to be drilled in the Malaysian Tertiary basins, and others are anticipated with application of new ideas and technology. In the Malay basin, Miocene sandstone reservoirs in Groups L and M have been considered as very [open quote]high risk[close quotes] targets, the quality of the reservoirs has generally been thought to be poor, especially toward the basinal center, where they occur at greater depth. The cause of porosity loss is primarily burial-related. Because of this factor and overpressuring, drilling of many exploration wells has been suspended at or nearmore » the top of Group L. In a recent prospect drilled near the basinal axis on the basis of advanced seismic technology, Groups L and M sandstones show fair porosity (8-15%) and contain gas. In the Sabah basin, turbidite play has received little attention, partly because of generally poor seismic resolution in a very complex structural setting. Only one field is known to produce oil from middle Miocene turbidities. However, using recently acquired 3-D seismic data over this field, new oil pools have been discovered, and they are currently being developed. These finds have created new interest, as has Shell's recent major gas discovery from a turbidite play in this basin.« less

Oil and Gas Developments in North-Central Texas in 1986

During 1986, the total number of wells drilled in north-central Texas decreased 36.34% compared to 1985. In Texas Railroad Commission (RRC) District 7B, successful development wells drilled decreased by 40.6%, and successful exploratory wells drilled decreased by 57.5%. The total number of wells drilled in RRC District 7B decreased 38.5% compared to 1985. RRC District 9 also had significant declines. Successful development wells drilled decreased 34.5%, and successful exploratory wells drilled decreased 29.9%. The total number of wells drilled in RRC District 9 decreased 33.3% compared to 1985.

Eugene Island Block 330 Field-- Development and Production History

Summary Eugene Island Block 330 field is currently the largest oil- producing field in federally owned offshore waters of the U.S. The field is located about 170 miles southwest of New Orleans (Fig. 1). The first leases were purchased in Dec. 1970. Three months later, a major discovery was apparent when exploratory wells drilled by Pennzoil and Shell on adjoining Blocks 330 and 331, respectively, established a 900-ft column of hydrocarbon-bearing sands. By the end of 1971, two platforms had been set, and development was under way. Four more platforms were set during 1972 and ultimately nine platforms were installed in the field. Initial production began in Sept. 1972 from Block 331. Hydrocarbon accumulation occurs in more than 25 sandstone reservoirs located at 2.200 to 12,000 ft. Recoverable reserves are estimated to be greater than 225 million bbl of liquid hydrocarbons and 950 Bcf of gas. Improved recovery operations began in Aug. 1975, utilizing water injection on Blocks 331 and 314 and through-gas injection in Dec. 1979 on Block 330. Through Dec. 1982, cumulative production was 224 million bbl of liquid and 1.03 Tcf of gas. This production is graphically illustrated in Figs. 2 and 3. This field is unique in the quick timing of operations to develop and initiate production. Introduction Eugene Island 330 field consists of portions of seven U.S. government lease blocks of 5,000 acres each as illustrated in Fig. 4. Operators are Exxon (2 blocks). Pennzoil (2 blocks), Shell Oil Co. (1 block), and Texaco Inc. (2 blocks). Several other operators having, interests jointly with Pennzoil are Exxon Corp., Mesa Petroleum Co., Mobil Corp., Pogo Producing Co.. Texas Production Co. and its subsidiaries, Pinto Inc. and Ecee Inc. Tenneco Inc. has interest jointly with Texaco in Block 338. This paper discusses the total geological complex and then follows the development and production history of the primary block, Eugene Island Block 330. Exploration Early exploration of the Eugene Island Block 330 area followed the Dec. 1970 offshore lease sale. Exploratory drilling began in Feb. 1971. By Oct. 1971, sufficient successful exploratory wells had been drilled to determine locations for five platforms. Subsequent exploratory and development drilling proved the necessity of four more platforms. As shown in Fig. 4, there have been 26 exploratory wells drilled and 9 eight-pile drilling and production platforms and 4 four-pile satellite production platforms set. Geology The field is an anticlinal structure on the downthrown side of a large arcuate-trending growth fault. JPT P. 1956^

Oil and Gas Developments in Oklahoma and the Panhandle of Texas in 1982

In 1984, the number of wells drilled in Oklahoma and the Panhandle of Texas increased 2.1%, recovering slightly from the precipitous drop in 1983. Exploratory tests continued to decrease, falling 8.5% from 1983 levels, but a slight increase of 2.6% was made in the number of development wells. Success rates for exploratory tests fell to 28.9% and increased slightly for development wells to 76.2%. Deep drilling virtually ceased with only 3 wells drilled below 20,000 ft. Of the 11,272 wells drilled in the province, 22 successful exploratory wells are considered especially significant. Both oil and gas production in the province increased in 1984.

Oil and Gas Developments in Oklahoma and Panhandle of Texas in 1981

In 1984, the number of wells drilled in Oklahoma and the Panhandle of Texas increased 2.1%, recovering slightly from the precipitous drop in 1983. Exploratory tests continued to decrease, falling 8.5% from 1983 levels, but a slight increase of 2.6% was made in the number of development wells. Success rates for exploratory tests fell to 28.9% and increased slightly for development wells to 76.2%. Deep drilling virtually ceased with only 3 wells drilled below 20,000 ft. Of the 11,272 wells drilled in the province, 22 successful exploratory wells are considered especially significant. Both oil and gas production in the province increased in 1984.

East-Central States

Tennessee had 351 oil and gas tests reported in 1980, up 54.6% from 1979. Exploratory wells (196) were up 84.9%. Development drilling increased 28.1%. Morgan, Scott, Fentress, and Overton counties accounted for more than 70% of the permits issued in 1980. Carbonates of Mississippian age continued to be the most important objectives in exploratory drilling. Almost all of Tennessee's oil and gas production is found in stratigraphic traps in the Fort Payne and Monteagle limestones. Leasing was very active in 1980. An estimated 5.5 million acres are under lease. Crude oil production in 1980 was 743,000 barrels, up 21.1% from 1979. Marketed natural gas in 1980 was 1,248,000 thousand cubic feet, and increase of 32.6% from 1979. Illinois had 1,980 oil and gas tests in 1980, up 75% from 1979. Exploratory tests numbered 451, up 92%, and were 18.8% successful. New field wildcats were 5.1% successful. Deeper pool tests were 25% successful. Of the 6 new field discoveries in 1980, 2 produce from Pennsylvanian rocks, 3 from Mississippian (Valmeyeran) and 1 from Devonian. Of the 36 new pools discovered, 31 produce from Valmeyeran, and 5 produce from Devonian. In Clay City Consolidated field, in the vicinity of the town of Clay City in Clay County, many excellent wells were completed, mostly in the Valmeyeran. This oil is stratigraphically trapped in a syncline. After years of being dominated by the anticlinal theory, much future exploration in Illinois probably will be directed toward the search of such pure stratigr phic traps. Drilling activity in Illinois in 1981 is expected to match or exceed the pace set in 1980. Crude oil production in Illinois in 1980 was 22,702,000 barrels, up 4.2% from 1979. Indiana had 725 oil and gas tests in 1980, up 48.3% from 1979. Exploratory wells increased from 184 in 1979 to 322 in 1980 and were 28% successful. New field wildcats were 8.8% successful. Of a total of 90 exploratory successes, 9 were new fields, 63 were new pools, and 18 were extensions to pools. Three new field discoveries, 1 new pool discovery, and 1 extension were gas wells; the rest were oil wells. Chesterian and Valmeyeran (Mississippian) rocks were the chief targets of exploration. Gibson, Posey, and Knox counties accounted for 73% of the exploratory successes. Average depth of the successful exploratory wells was 2,187 ft, 406 ft deeper than the average in 1979. The Trenton field of east-central Indiana, discovered in 1886, received renewed interest in 1980. The increased dri ling activity in Indiana in 1980 is expected to continue in 1981. Estimated crude oil production in Indiana in 1980 was 4,520,000 barrels, a decline of 200,000 barrels from 1979. In Kentucky, 1,244 oil and gas tests were drilled in 1980, up 41.8% from 1979. The 437 exploratory tests, up from 332 in 1979, resulted in 54 oil wells, 31 gas wells, and 3 combination oil and gas wells, a success rate of 20.1%. Exploratory successes included 18 new pool wildcat discoveries, 6 deeper pools, 5 shallower pools, and 59 extensions. No new fields were discovered. Development wells were 60.8% successful and included 391 oil wells, 92 gas wells, and 8 combination oil and gas wells. Oil production in Kentucky in 1980 was 5,945,666 barrels, an increase of 7.8% from 1979. Gas production, 96% of which is from eastern Kentucky, was 58,274,375 thousand cubic feet, virtually the same as in 1979. In 1980, the number of permits issued reached an all-time high of 4,132, 40% of which w re in the south-central portion of the state. Drilling activity in 1981 should exceed that of 1980.

Developments in West Coast Area in 1979

New-field discoveries in California were down in 1979 from the previous year. The total exploratory footage drilled was slightly lower, but the total number of successful exploratory wells was up 19% from 1978. One new oil field and 5 new gas field discoveries were reported in California. None of these discoveries appear to be of major size. During 1979, hydrocarbons were discovered in commercial quantities for the first time in Oregon--the Mist Gas field, in the northwestern corner of the state, in Columbia County. A pipeline was constructed for initial production in late 1979. This discovery has spurred drilling and leasing activity. Mobil drilled a second deep exploratory well in Oregon, to 10,412 ft, which was subsequently abandoned. Only 1 shallow oil and gas explora ory well was drilled in Washington State this year. As yet it has not been completed. Development drilling in California, although down from 1978, continued at an active pace and is related largely to steam-flood projects. Production of oil outstripped additions to reserves by 285.8 million bbl in 1979. Geothermal activity increased in California's Imperial Valley and Geysers area. Southern California Edison Co. has begun construction of a 10-Mw generating plant near Brawley in the Imperial Valley. Two other geothermal projects in the Imperial Valley sponsored by Southern California Edison include the development of a 50-Mw unit near Heber and a prospective 10-Mw plant south of the Salton Sea. Westmoreland Geothermal Associates also have plans to develop a plant in the valley. In the Geysers area, Sacramento Municipal Utility District plans to construct a 55-Mw plant. The Geysers capacity is expected to increase to 1,238 Mw by the end of 1982.

Developments in West Coast Area in 1978

New-field discoveries in the West Coast area were down in 1978 from the previous year, although the total exploratory footage drilled was significantly higher and the total number of successful exploratory wells in California was up 12% from 1977. One new oil field and 6 new gas field discoveries were reported in California. None of these discoveries appear to be of major size and 1 gas field discovery was subsequently abandoned. Mobil commenced drilling a deep test in Oregon in 1978 on their large land block in the Willamette Valley. The well has subsequently been abandoned. No drilling activity was reported in Washington. Development drilling in California, although down from 1977, continued at an active pace and is related largely to steam-flood projects. Production of oil outstripped additions to reserves by 164 million bbl in 1978. Geothermal development drilling continued at The Geysers and in the Imperial Valley. The geothermal discovery well by McCulloch of the South Brawley field in the Imperial Valley is the deepest geothermal well drilled in California. This well may open a broad new area for deep fracture production. The first Imperial Valley geothermal power plant will begin generating electricity this year and 6 more plants are in various stages of design and construction throughout the valley. The Geysers capacity is expected to increase to 1,238 Mw by the end of 1982.

Developments in East-Central States in 1978

Oil production in Illinois, Indiana, Kentucky, and Tennessee in 1978 totaled 34,351,000 bbl, down 10.4% from 1977. Gas production in Kentucky was 70 Bcf, an increase of 15%; gas production in the other states is relatively insignificant. Oil and gas drilling tests numbered 2,909, down 1.8% from 1977. Exploratory tests totaled 1,034, down less than 1%; 210 (20.3%) were successful. Tennessee had 222 oil and gas tests in 1978, down 9% from 1977. Exploratory wells (150) were down 3.8%; development wells (72) were down 19.3%. Success rate for exploratory wells was 40.0%, and for development wells, 73.6%. Although wells were drilled in 18 counties, Fentress, Morgan, and Scott Counties were the most active, accounting for 175 completions, including 47 exploratory wells. Total footage for all tests was 365,723, of which 108,194 was exploratory. Carbonate rocks of Mississippian age continued to be the most important targets of exploratory drilling. Most completions were made in the Fort Payne and Monteagle limestones. Enough additional gas was found in 1978 in Gruetli field to warrant construction of a pipeline. The gas is from the Trenton (Ordovician). Illinois had 1,094 oil and gas tests in 1978, down 1% from 1977. Exploratory tests numbered 265, up 10%, and were 14.7% successful. Total footage drilled, including service wells and structure tests, was 3,084,666, down 1%. The highlight of 1978 activity was the discovery of Fort Payne (early Valmeyeran) production in New Harmony Consolidated field in White County. Through January 1979, 12 Fort Payne producers had been reported. Initial production figures ranged up to 600 BOPD and averaged 210 BOPD. Production is from broken porosity between 4,000 and 4,500 ft. Testing of the Salem Limestone and the immediately underlying Ullin Limestone (both Valmeyeran) accounted for 28% of the total tests in 1978. A total of 84 Salem producers was completed in 24 fields; 33 Ullin producers were com leted in 13 fields. The two formations accounted for more than 40% of the 1978 discoveries. Most of the Salem and Ullin activity is in a 9-county area with Wayne County at the center. Crude oil production in Illinois in 1978 was 23,362,000 bbl, down 8.8% from 1977. Indiana had 669 oil and gas tests, up 10% from 1977. There were 268 exploratory tests, of which 14.9% were successful. Total exploratory footage was 531,760. Exploration and drilling activity remained principally in southern Knox County and northern Gibson County. At least half of the successful exploratory wells tested the St. Louis, Salem, or Harrodsburg Limestones. Of these, all but 4 resulted in completions in 1 or more of these stratigraphic units. The remaining 4 discovered oil in shallower pays. Exploration for St. Louis, Salem, and Harrodsburg reservoirs should spread to other fields producing from shallower pays in southwestern Indiana. Also, in large completely untested areas in southwestern Indiana, these deeper rock units should be considered to be promising targets for ex loration. Crude oil production in Indiana in 1978 was 4,684,000 bbl, down 11.9% from 1977. In Kentucky 924 oil and gas tests were drilled in 1978, down 8.1% from 1977. The 351 exploratory tests, down from 365 in 1977, resulted in 38 oil wells and 33 gas wells, a success rate of 20.2%. Development wells were 63% successful, resulting in 256 oil wells and 105 gas wells. Exploratory interest in Valmeyeran production in western Kentucky waned in 1978, despite encouraging discoveries elsewhere in the Illinois basin. Seismic activity in eastern Kentucky was quite good, but deeper drilling declined despite large blocks of acreage held by the majors. Major discoveries in Cambrian-Ordovician strata in the Rome trough will be necessary to reverse a declining production trend. Crude oil production in Kentucky in 1978 was 5,712,339 bbl, down 13.19% from 1977.

Reservoir performance of the Geysers Field

The Geysers Field, located in Northern California, has an installed generating capacity of 502 MWe. Total withdrawal rate is approximately 8-5 million lb/h of steam from 95 wells. Four new generating plants are currently under construction, which will bring the installed capacity to 908 MWe by 1979. The reservoir rock consists of naturally fractured graywacke, a very competent rock with low interstitial porosity and permeability. The reservoir contains dry steam with an initial pressure of approximately 514 psia at sea level datum. Static pressure gradient is that of saturated steam to the total depths of wells drilled to date. The initial development at The Geysers Field occurred in an area which has two shallow dry steam anomalies. Recent studies have shown that the steam in these anomalies is being fed through fractures connecting them with the deeper regional fracture system. Development of the regional system has created two distinct pressure sinks. The larger of the two pressure sinks is in the oldest and most developed portion of the field. This sink has grown larger with the addition of new production capacity. There is no pressure interference between the two sinks, but pressure interference between wells in a given pressure sink is very rapid. Pressure behavior at observation wells in these sinks resembles an ideal single-phase system with constant pressure boundaries. The expansion of the field has been the result of continued exploratory drilling and testing of new step-out wells. Based on the successful exploratory wells drilled to date, it is estimated that the generating capacity of The Geysers could reach 1800 MW by the mid-1980s.

Developments in East-Central States in 1975

Total oil production in Illinois, Indiana, Kentucky, and Tennessee in 1975 was 39 million bbl, down 5.3% from 1974. This compares with a decline of 8.9% in 1974 and of 11.9% in 1973. All 4 states had decreased production. Gas production in Kentucky in 1975 was 62.9 Bcf, a decline of 9.8% from 1974. Gas production in the other states is insignificant. A total of 2,445 oil and gas tests was drilled in 1975, up 24.5% from 1974 and 60.4% from 1973. Exploratory tests totaled 868, up 31.9% from 1974; of these 168 (19.4%) were successful. Tennessee had 203 oil and gas tests in 1975, up 50.4% from 1974. Exploratory tests were up 68.2%. Most of the drilling was in Morgan, Fentress, and Scott Counties. Successful exploratory wells included 23 new fields, 8 new pools, and 13 extensions. None of the discoveries adds significant reserves. At Indian Creek field, operators began recycling gas to the Fort Payne reservoir for pressure maintenance, the first known secondary-recovery project in Tennessee. Oil and gas potential in fractured lower Trenton rocks in the Cumberland Plateau and eastward into the Valley and Ridge province was suggested by several wells in Grundy County that found gas in these rocks. Leasing activity continued in the Mississippian play in the northern Cumberland Plateau. Plans for deep tests in eastern ennessee appear to have been shelved because of tightened exploration budgets. Illinois had 956 oil and gas tests in 1975, up 20.3% from 1974. Exploratory tests were up 14.9%, development wells 22.3%. Two oil fields, 6 successful newpool wildcats, 6 deeper pools, 8 shallower pools, and 12 extensions were discovered. None of the discoveries adds significantly to reserves. The two new fields are Louisville in Clay County and Vergennes in Jackson County. Production in Louisville is from the Aux Vases, McClosky, Salem, and Ullin (all Mississippian). Production in Vergennes is from the Devonian. Deep testing increased in Illinois. Of the 106 new-field wildcats drilled in 1975, 2 tested Pennsylvanian rocks, 31 Mississippian (all but 6 Valmeyeran), 59 Devonian-Silurian, 10 Ordovician (all Trenton), 1 Cambrian-Ordovician (Knox), 2 Cambrian, and 1 Precambrian. A Cambri n test in Johnson County was drilled to TD of 14,274 ft, a new depth record in Illinois. It was dry and abandoned, and Johnson County has no production. Indiana had 374 oil and gas tests in 1975, down from 376 in 1974. Exploratory holes were down from 168 to 156. Development wells were up from 208 to 218. Success ratio of exploratory drilling was 12.8%. Successful exploratory wells included 3 new fields, 13 new-pool wildcat discoveries, and 5 extensions. One of the new fields, Elnora West, was an old dry hole that involved no new footage. A new-pool discovery, the Salem Limestone in Odon South field, established an additional productive reef-associated structure in Daviess County. In Owensville North Consolidated field, Gibson County, 12 wells were completed in the Salem in 1975. Drilling in 1976 is expected to continue at the current rate. Deeper stratigraphic units probably will command increased attention. A total of 1,011 wells was drilled in Kentucky in 1975, up 45% from 1974. They included 315 exploratory wells (up 71.2%), 597 development wells (up 25.9%), and 99 miscellaneous wells. The success percentage for exploratory wells was 23.8% and development wells 58.8%. Successful exploratory tests included 17 new fields, 6 new-pool wildcats, 25 extensions, 11 shallower pool tests, and 16 deeper pool tests. Recent new discoveries in Lower Mississippian strata have caused many old wells to be deepened and many new tests to be drilled to the Fort Payne-Warsaw-Salem sequence in the Illinois basin part of Kentucky with much success. The discovery of Knox and shallower Ordovician production in Adair County has caused additional drilling and exploratory successes in adjoining Green County, and much more Knox prospecting throughout central Kentucky. Devonian shale-gas exploration will be curtailed severely in 1976 because of increased drilling costs. Several tests were drilled, the deepest of which was a 14,340-ft Precambrian test in Webster County.

Developments in South Texas in 1975

Drilling activity in South Texas increased from 2,147 wells in 1974 to 2,614 in 1975. The percentage of successful exploratory wells increased from 30 in 1974 to 38.7 in 1975. Although 383 more development wells were drilled in 1975 than in 1974 for a 30.6% increase, development-well successes were down only 0.6% over the 1974 percentage of 77.4. The main exploration targets were the Frio and Wilcox trends followed in order by the Cretaceous, Claiborne, Miocene, and Vicksburg. The Wilcox play in Webb and Zapata Counties continues to be very active. South Texas offshore activity was down with a total of 21 wells drilled versus 28 for the year before. The success ratio for the offshore exploratory wells was only 9.5%. A boom in development-well activity developed in Distric 1 due to the Austin Chalk play. This accounts for the 58.1% increase in development-well activity in this area.

Developments in East-Central States in 1974

Total oil production in Illinois, Indiana, Kentucky, and Tennessee in 1974 was 41 million bbl, down 8.9% from 1973. Tennessee had a 275% increase; all the other states had decreases. Gas production in Kentucky was 69.7 Bcf, about the same as in 1973. Gas production in the other states is not significant. A total of 1,964 oil and gas tests was drilled in 1974, up 28.9% from 1973. Exploratory tests totaled 658, up 16.5%; of these, 125 (19%) were successful. Tennessee had 135 oil and gas tests in 1974, up 37.7% from 1973. Exploratory tests were up 28.8%. Total footage drilled was 214,877, of which 140,343 ft was exploratory. Most of the drilling was in Morgan, Scott, and Fentress Counties, where the primary objective was the Lower Mississippian Ft. Payne carbonate rock. Successful exploratory wells in 1974 included 10 new fields, 4 new-pool wildcat discoveries, 1 deeper pool discovery, and 13 extensions. Indian Creek field in Morgan County was the most significant discovery in 1974. Almost all production from this field is from the Ft. Payne; primary reserves are estimated at more than 1 million bbl. Two deep tests, a 6,334-ft basement test in DeKalb County, and a 3,995-ft test in the Copper Ridge Dolomite in Smith County, were drilled in 1974; both were unsuccessful. Several majors reportedly are leasing large blocks in eastern Tennessee. Leasing also continued in the area of Morgan, Scott, and Fentress Counties. Crude oil production in Tennessee in 1974 was 768,700 bbl, up from 205,000 bbl in 1973. Illinois had 795 oil and gas tests in 1974, up 43% from 1973. Exploratory tests were up 12.8%. Total footage drilled in oil and gas tests and service wells was 2,023,761, up 39.9%. Six new fields, 16 extensions, 3 new-pool wildcats, 5 deeper oil pools, and 2 shallower oil pools were discovered. None of the discoveries adds significantly to reserves. About 75% of the 103 new-field wildcat tests drilled were on the shelf area west and northwest of the deep Fairfield basin. Sixty-five of the new-field wildcats tested Devonian or deeper strata. One of the outstanding features of 1974 activity was the large number of wells testing the Mississippian Ullin Limestone (Valmeyeran). For example, Clay City Consolidated field, which had only 3 Ullin producers at the end of 1973, had 43 Ullin test in 1974, of which 14 were completed in the Ullin. Indications are strong that several deep tests will be drilled in Illinois in 1975, with Trenton and deeper strata as their objective. Activity south of the Rough Creek lineament is expected to increase in 1975. Crude oil production in Illinois in 1974 was 27,554,000 bbl, a decline of 10.2%. Indiana had 376 exploratory and development tests in 1974, up 57.3% from 1973. Twenty-nine more exploratory wells were drilled in 1974 than in 1973. Successful exploratory percentage increased from 10.1% in 1973 to 14.1% in 1974. With a few exceptions, all of the drilling activity in 1974 was in the Illinois basin part of Indiana. Exploratory successes included 7 new fields, 14 new pools, and 3 extensions. Three of the 1974 discoveries were on structures that exhibit anomalies which suggest buried Silurian reefs. Sizable undrilled blocks exist in the areas of expectable reefs, and continued testing of these areas is assured. Because of higher crude prices, many old fields which had become uneconomic probably will receive remedial action. Some attempts at tertiary recovery also are ant cipated. Estimated crude oil production in 1974 is 4,950,000 bbl, a decline of 6.8%. A total of 658 oil and gas tests was drilled in Kentucky in 1974, up 4.3% from 1973. Of 184 exploratory tests drilled, 44 (23.9%) were successful. The exploratory successes included 7 fields, 25 extensions, 4 deeper pools, and 8 shallower pools. A Cambrian test in Stephens field, Elliott County, was drilled to TD 9,473 ft and completed as a 500 Mcf gas producer in the Ordovician Wells Creek Formation at 4,875 ft. Among unsuccessful deep exploratory tests in 1974 were a Precambrian test drilled to TD 13,035 ft in Big Sandy field, Floyd County; 2 Knox tests a little more than TD 6,000 ft, 1 in Breckinridge County and 1 in Johnson County; and a 7,608-ft Antietam test in Morgan County. The last 3 wells are new-field wildcats. At year-end a scheduled Cambrian test was drilling in Webster C unty, and Texas Gas was scheduled to complete a Grayson County test to a depth in excess of 13,000 ft.

Developments in South Texas in 1974

Drilling activity in South Texas increased from 1,733 wells drilled in 1973 to 2,282 wells drilled in 1974. The percentage of successful exploratory wells increased from 14% in 1973 to 32% this year. Development-well successes were up 1.1% over the 1972 percentage of 76.3%. The main exploration targets were the Frio and Wilcox trends with the Cretaceous and Miocene not far behind. The Wilcox play in Webb and Zapata Counties continued to have the most activity. At year-end the number of active rotary rigs was 33. Offshore activity was up with 163 new wells drilled versus 72 for the year before. However, the success ratio for reported exploratory wells was only 8%.

North American Drilling Activity in 1968

Total drilling activity in North America in 1968 amounted to 37,444 wells and 169,232,679 ft of hole compared with 38,183 wells (FOOTNOTE 4) and 162,924,271 ft4 of hole reported in 1967. This represents a decrease of 2% in number of wells but an increase of 4% in total footage drilled. Canada and Mexico showed increases in both total wells and footage. The United States experienced a decline in the number of wells drilled but an increase in drilled footage. Exploratory drilling in Canada and Mexico showed increases in both wells and footage, whereas in the United States, the number of wells declined and total footage increased. Actual figures for exploratory wells, with corresponding 1967 values in parentheses, are: Canada, 1,609 wells (1,448) and 7,543,693 ft (6,420,367); Mexico, 138 wells (135) and 1,331,996 ft (1,295,160); United States, 8,879 wells (9,059) and 50,958,038 ft (49,124,222). A total of 1,785 exploratory wells out of a total of 10,626 were found to be capable of hydrocarbon production. This gives a North American of about 1:6 (16.8%) compared with 1:5 (19.4%) in 1967. Canadian exploration success was stable at 28.2%, the same as in 1967. Mexican exploratory discoveries resulted in an increase in success pe centage from 23.7 in 1967 to 27.5 in 1968. In the United States, the percentage of successful exploratory wells decreased from 17.6 in 1967 to 14.6 in 1968. This is the lowest success percentage since these statistics were first compiled in 1946. The continued downturn in exploratory drilling and discovery ratio in the United States must, however, be weighed against the fact that 2 of the discovery wells found fields on Alaska's north slope which, in terms of our total hydrocarbon reserves, will possibly be more significant than any other discoveries in the history of this survey. Reserve estimates made by the committee indicate that, excluding the 2 discoveries on Alaska's north slope, the United States exploration effort found somewhat less than 1 billion bbl of oil and just under 6 trillion cu ft of gas. These volumes are approximately the same as in 1967 and were found with fewer, but deeper, exploratory wells. The determination of whether the industry in the United States during 1968 experienced one of its worst years (based on percentage) or one of its best (based on volume of hydrocarbons found) must be left to individual judgment.

Review of 1967 Petroleum Developments in South America, Central America, and Caribbean Area

This review includes data from 29 countries, of which 11 are producers of petroleum. Their combined production during 1967 was approximately 1,653,216,000 bbl, or an average rate of 4,529,353 b/d. This is about 13% of the world's total oil production during 1967. Within the area reviewed Venezuela experienced a 5.1% increase in production from 1966 and had 78% of the 1967 total. The other oil-producing countries of the area combined had a 12.6% increase in production from 1966 and contributed 22% of the 1967 total. For the overall area, the total 1967 exploration activity in 16 countries, in party-months, was changed little from the previous year. Activity by surface-geology parties decreased 15% whereas activity by seismograph parties increased 14%. The totals based on d illing statistics from 14 countries decreased in 1967; wells drilled decreased 16%, footage drilled decreased 4.7%, exploratory wells completed decreased 5%, and successful exploratory wells decreased 20%. There are indications that the area reviewed may be entering a period of increasing petroleum exploration and development. The known hunting grounds for possible further investigation are extensive.

Developments in North-Central Texas in 1964

North-Central Texas is District 14, composed of Texas Railroad Commission Districts 7-B and 9. The number of wells drilled during 1964 in this area was 3,582, compared with 4,210 in 1963, a decrease of 15 per cent. Successful exploratory wells numbered 173, compared with 219 in 1963. Production was down 935,500 barrels, but was 11.5 per cent of the State total. Shallow reservoirs in several counties make the district attractive to independents and to a few majors. The use of seismic information for selecting drilling sites, except in areas of shallow production, either increased or remained constant during 1964.

Developments in Southeastern States in 1963

Drilling in the southeastern states increased sharply in 1963, with 893 wells drilled as compared with 697 in 1962. Mississippi was again the most active state and had all of the successful exploratory wells. Exploratory drilling increased by 18%, while maintaining an 11% success ratio. Development drilling increased by 38%; however, the success ratio dropped by 5.3%. Development drilling in Alabama was down slightly, but exploratory drilling nearly doubled. In Florida 1 successful development well and 4 dry exploratory wells were drilled. Three dry wells were drilled in Georgia.

Developments in North Texas in 1963

The number of wells drilled in this area in 1963 was 1,987 compared with 2,584 in 1962, a decrease of 597 or 23%. Successful exploratory wells were 102 as against 107 in 1962. The total production was down 55,000 bbls. but was 7.6% of the total for the state. Shallow pays in several of the counties make the district attractive for the independents as well as the major companies. The use of seismic information is increasing for selecting locations for wells everywhere except in the areas of shallow production.