The Estancia Basin of central New Mexico is an asymmetric, north-south-trending structural depression that originated during the Pennsylvanian. The present-day basin covers 1,500 mi 2 and is defined approximately by the Estancia Valley. It is bounded on the east by the late Paleozoic Pedernal uplift, on the west by the Tertiary-age Sandia, Manzano, and Los Pinos Mountains, on the north by the Española Basin, and on the south by Chupadera Mesa. Depth to Precambrian basement ranges from more than 8,500 ft in a narrow graben (Perro sub-basin) in the eastern part of the basin to less than 1,000 ft on a shelf to the west.Basin fill consists primarily of Pennsylvanian and Wolfcampian sandstones and shales in the Perro sub-basin and sandstones, shales, and marine limestones on the shelf. In the Perro sub-basin, reservoirs are fine-to coarse-grained sandstones with relatively low permeabilities and porosities. On the shelf, reservoirs are mostly fine-to coarse-grained sandstones with porosities that range from 0 to 16% and average approximately 10%. Most limestones on the shelf have less than 5% porosity and are poor reservoirs; however, algal grainstones and recrystallized lime mudstones appear locally to form good reservoirs with porosities that can exceed 20%.Mature to marginally mature dark-gray to black Pennsylvanian shales are probable source rocks. Thermal Alteration Index ranges from 2.0 to 3.2. Shales become thermally mature with depth in the Perro sub-basin. On the western shelf, shales become mature to the west as a result of increased heating from the Rio Grande rift. Total organic carbon exceeds 0.5% in many shales, sufficient for hydrocarbon generation. Kerogen types are mixed algal, herbaceous, and woody, indicating that gas, or possibly gas mixed with oil, was generated. Kerogens in the shales of the Perro sub-basin are entirely woody, gas-prone types. In limestones and shales of the western shelf, kerogens have mixed marine and continental provenance, indicating that both oil and gas may have been generated on thermally mature parts of the shelf.Forty-three exploratory wells have been drilled in the basin. Only 17 of those wells have been drilled to Precambrian. Density of wells that penetrate the lowermost Pennsylvanian is less than one well for every three townships. Most of the wells were drilled before 1950 and lacked modern logs and testing apparatus with which to evaluate fully the drilled section. In spite of this, numerous shows of oil and gas have been reported; many of these shows are well documented by modern logs and tests, especially from wells drilled since 1970. During the 1930s and 1940s, carbon dioxide gas was produced commercially from two small fields on the western flank of the basin.

Figure 2. Structure contour map of New Mexico on top of Precambrian basement. Contours refer to feet above or below (-) sea level. Simplified from Broadhead (Broadhead et al., 2009).

The Tucumcari Basin of east-central New Mexico is an asymmetric structural depression that existed as a depositional basin from Strawn (Middle Pennsylvanian) until late Wolfcampian (Early Permian) time. Depth to Precambrian ranges from 6,500 ft in the southern part of the basin to more than 9,000 ft in the northern part of the basin. High-angle faults form the northern, western, and eastern margins of the basin. Faults cut Pennsylvanian and Wolfcampian strata but do not generally offset post-Wolfcampian strata. To the north and west, the basin is bounded by the Sierra Grande and Pedernal Uplifts. To the east, the Frio Uplift separates the Tucumcari Basin from the Palo Duro Basin of the Texas panhandle. No major structural discontinuities separate the basin from a shallow shelf to the south.Correlations between fusulinid biostratigraphic data, geophysical logs, cores, and drill cuttings indicate the facies and thickness patterns of Pennsylvanian and Wolfcampian strata are structurally controlled. Coarse-grained arkosic sandstones that were deposited in the northern and western parts of the basin were derived from the highlands of Precambrian granitic rocks that formed the northern and western margins of the basin. These sandstones are good reservoirs and exhibit both primary and secondary porosities. High-energy limestones of Pennsylvanian through Wolfcampian age were deposited in the southern part of the basin and are possible reservoirs. Dissolution porosity may have developed in the limestones that are truncated by a basin-wide unconformity at the top of the Pennsylvanian. Porous dolostones of Wolfcampian age cover the Frio Uplift on the eastern side of the basin and are good reservoirs.Thermally mature oil-and-gas source rocks are Pennsylvanian and Wolfcampian marine shales that were deposited throughout the Tucumcari Basin. Post-Wolfcampian strata are thermally immature.Two presently noncommercial to marginally commercial pools of oil and gas, the Latigo Ranch and the T-4 Cattle Company pools, have been discovered in Strawn sandstones in the northern part of the basin. Oil generated in upper Paleozoic strata has migrated vertically through faults into Triassic strata; two accumulations of heavy oil, the Santa Rosa tar sands and the Newkirk oil pool, are in Triassic sandstones and have combined reserves of 153 million bbls of oil.

is a senior research scientist at the Bureau of Economic Geology with research interests in sedimentology, reservoir characterization, sedimentary petrology, and clastic diagenesis. She received a B.A. degree from the University of Rochester and an M.A. degree and a Ph.D. from the University of Texas at Austin, all in geology. She has been an AAPG Distinguished Lecturer.

We used hydrologic models to explore the potential linkages between oil‐field brine reinjection and increases in earthquake frequency (up to Md 3.26) in southeastern New Mexico and to assess different injection management scenarios aimed at reducing the risk of triggered seismicity. Our analysis focuses on saline water reinjection into the basal Ellenburger Group beneath the Dagger Draw Oil field, Permian Basin. Increased seismic frequency (>Md 2) began in 2001, 5 years after peak injection, at an average depth of 11 km within the basement 15 km to the west of the reinjection wells. We considered several scenarios including assigning an effective or bulk permeability value to the crystalline basement, including a conductive fault zone surrounded by tighter crystalline basement rocks, and allowing permeability to decay with depth. We initially adopted a 7 m (0.07 MPa) head increase as the threshold for triggered seismicity. Only two scenarios produced excess heads of 7m five years after peak injection. In the first, a hydraulic diffusivity of 0.1 m2 s−1 was assigned to the crystalline basement. In the second, a hydraulic diffusivity of 0.3 m2 s−1 was assigned to a conductive fault zone. If we had considered a wider range of threshold excess heads to be between 1 and 60 m, then the range of acceptable hydraulic diffusivities would have increased (between 0.1–0.01 m2 s−1 and 1–0.1 m2 s−1 for the bulk and fault zone scenarios, respectively). A permeability–depth decay model would have also satisfied the 5‐year time lag criterion. We also tested several injection management scenarios including redistributing injection volumes between various wells and lowering the total volume of injected fluids. Scenarios that reduced computed excess heads by over 50% within the crystalline basement resulted from reducing the total volume of reinjected fluids by a factor of 2 or more.