--> --> Abstract: Development of the Unconventional Reservoirs in the Delaware Basin, West Texas and Southeast New Mexico, USA with a Case Study in Horizontal Wellbore Petrophysical and Geochemical Evaluation, by Kenneth M. Schwartz, Peter Nester, Jessica Allen, Christopher Schmidt, and Gary Muscio; #90180 (2013)

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Development of the Unconventional Reservoirs in the Delaware Basin, West Texas and Southeast New Mexico, USA with a Case Study in Horizontal Wellbore Petrophysical and Geochemical Evaluation

Kenneth M. Schwartz, Peter Nester, Jessica Allen, Christopher Schmidt, and Gary Muscio
Chevron Mid-Continent Business Unit, Houston, TX, USA

The Delaware Basin, a western sub-basin of the Permian Basin, is located in west Texas and southeast New Mexico. Peak production in the basin was reached in the early 1970’s with early exploration and development targeting primarily Devonian or older gas-filled structural traps. However, advancements in horizontal drilling, hydraulic fracturing technologies, and the industry’s focus on oil assets have led the resurgence in drilling activity in the basin targeting the tight sands and shales of the Bone Spring and Wolfcamp formations. Chevron is well-positioned with over one million acres of fee mineral ownership and leases in the basin and is currently building a business strategy for long-term production growth.

The Bone Spring and Wolfcamp formations represent approximately 6000 feet of shelf to basin stratigraphic intervals deposited along the southwest margin of the North American craton in the late Permian. Rapid subsidence during the Permian accommodated a large sediment and organic influx into the foreland basin initiating the depositional framework for the play. Alternating periods of carbonate buildup and debris flows with clastic deepwater channel deposition (known as reciprocal stratigraphy) mimic relative sea-level fluctuations. Tertiary Basin and Range extension bounds the basin to the west which marks the only major post-Permian tectonic activity. Consequently, the basin is structurally asymmetric with an eastern bias and a gentle dip driving the sediments through a longer thermal maturity. The asymmetric geometry appears to have implications on seal.

The new growth intervals include at least 10 productive Permian-aged horizontal targets; the Wolfcamp, Avalon, and Bone Spring shales, the Bone Spring and Delaware Mountain Group low-resistivity sands. Thus, on a single well-pad location, a large stacked resource opportunity may exist which complicates the long term development strategy. Strategic joint ventures were initiated throughout the basin which accelerated our subsurface understanding, but also allowed for optimal completion and drilling design standardization. This paper will review these growth horizons in detail. Ultimately, the principle challenge is building a development plan with a drilling queue based on geologic risk, lease maintenance, commercial infrastructure, and upside potential criteria. An ArcGIS-based workflow was built which spatially weights these criteria and force ranks our leases by net present value. This tool allows for quick lease evaluation and prioritization and is the foundation for our multi-rig drilling queue.

Case Study in Horizontal Petrophysical and Geochemical Evaluation of the Terra Nemo Avalon shale well

Chevron drilled the Terra Nemo exploration well targeting the Avalon shale (approximately 10000 feet TVD). A robust formation evaluation was conducted which included a high quality logging suite, conventional core, side-wall core, well-site cutting analysis, and post-drill geochemical analysis of headspace gas, mud gas, and produced liquids. Ultimately, petrophysical logs and well-site cutting analysis were used to identify the optimal landing zone based primarily on organic richness. The Avalon shale shows moderate generation potential and uniformly type II/III kerogen (oil and gas prone). Additionally, the shale revealed low levels of maturity based on Rock Eval analysis, consistent with incipient generation of liquids. Geochemical parameters (e.g. Oil Saturation Index OSI and Production Index PI) indicate low levels of liquids concentration throughout the pilot hole. However, the lateral hole shows elevated levels of OSI (110). Continued elevated TOC values were observed though the lateral section, but, heavier gas ratios varied. Changes in the heavier gas concentrations generally correlated with increases in molybdenum, selenium, uranium, and vanadium. The results from Terra Nemo on source rock character are consistent with the greater regional dataset.

Mud gas and headspace gas samples were analyzed for molecular and stable isotope composition for an evaluatation of origin of gas and its maturity. Both types of gases show increased levels of wetness. Supported by the isotopic composition, this indicates predominantly thermogenic origin, associated with liquids. Mud gas from isotubes is isotopically lighter than headspace gas, potentially indicating mixing with biogenic gas. The light isotopic composition of mud and headspace gas from pilot and lateral hole indicates source rock maturities in the oil window (early oil and main oil). The gas derived from source rocks suggest early to main stage of oil maturity.

Imaging logs showed many drilling-induced fractures in the target intervals but formation testing with straddle-packers in the pilot did not provide any successful pressures or formation fluid samples due to the low permeability and lack of a natural fracture network in the near-wellbore region. However, we were able to successfully induce fractures in multiple zones using a micro-frac tool and the results compare favorably with geomechanical logs. The well was drilled in a toe up fashion to improve the drawdown early in the production life. During the initial 12 hours of flow-back, 350 barrels of water was produced with the majority from far half of the lateral. However as the oil rate began to increase, water production increased in the near half of the lateral. LWD measurements in the lateral showed significant lithology variations along the 3300 ft. interval, which may be related to the flow variation observed.

AAPG Datapages/Search and Discovery Article #90180©AAPG/SEPM/China University of Petroleum/PetroChina-RIPED Joint Research Conference, Beijing, China, September 23-28, 2013