Utilizing all of the information available, the geologists and engineers 

 formed a program for the drilling of the American Production & Exploration 

 Company's No. 1 Juan Cuervo (fig. 41-22), and estimated drilling and com- 

 pletion costs (fig. 41-23). This wildcat was spudded, and after 1100 feet had 

 been drilled, an electric-log survey was made. It indicated no fresh-water 

 reservoirs below 860 feet, and surface casing was set at 1000 feet in order to 

 protect fresh-water sands and porous limestones which were noted in the alluvial 

 sands and gravels and uppermost Permian sands and limestones. After drilling 

 out beneath the surface pipe, cores were taken from several sands and dolomites 

 of the lower Permian section, which had carried faint shows of gas as noted by 

 the mud-logging unit. However, cores, electric-log surveys, and formation 

 tests indicated that these reservoirs were wet (carried water). A section of 

 Pennsylvanian dense limestone 620 feet thick was topped at 1580 feet, and no 

 shows of oil or gas were noted in the cores and cuttings. A predominantly 

 clastic Mississippian section was reached at approximately 2200 feet, and scatter- 

 ed non-commercial shows of oil and gas were noted in cuttings and cores of sands 

 and sandy shales. 



At 3190 feet the driller noticed a sharp drilling break; the mud-logging 

 unit recorded an abnormally high content of gas and oil from analyses of the 

 drilling mud and cuttings; and the geologist found that the lithology of the 

 cuttings had changed from shale to limestone. Cores were then taken of the 

 interval 3195 to 3240 feet. Core recovery was approximately 70 percent and 

 consisted of porous, oil-saturated limestone. When a formation test taken of 

 this interval flowed 29 degree gravity oil at the rate of 18 barrels per hour 

 through 1/4 -inch bottom and i/g-inch top chokes with an estimated gas-oil ratio 

 of 1300:1, Amprex's geologist realized that oil production had probably been 

 established in the Arenoso Basin. The average formation flowing pressure was 

 1450 psi, and the shut-in formation pressure was 1580 psi. An additional 60 

 feet of oil-saturated limestone was cored and tested before the drill encountered 

 shale, indicating 110 feet of limestone "pay". Core analyses and electrical sur- 

 veys of the productive zone later established several dense, impermeable lime- 

 stone beds, revising the productive interval to 98 feet of net effective limestone 

 "pay". A study of the fossil content of this limestone by paleontologists indicat- 

 ed that it was Devonian. Three additional oil-productive limestone stringers 

 were found in the Devonian section within the next 500 feet. Each of these pays, 

 although relatively thin, was considered productive; combined, they had a net 

 effective porosity thickness of 60 feet. 



Shale, encountered beneath the deepest of these Devonian limestone pays, 

 was continuously cored for the next 300 feet. While coring at 4100 feet, the 

 driller noted an abrupt drilling break, and oil and gas began cutting the drilling 

 mud. After 10 feet beneath this break was cored, the core barrel was pulled, 

 and approximately 10 feet of highly porous, vugular, fractured, oil-saturated 



853 



