Walter B. Ayers

Detection of cyclic patterns using wavelets: An example study in the Ormskirk Sandstone, Irish sea

This study shows how wavelet analysis can be used on well log and drill core data to identify cyclicity in sedimentary sequences. Three possible methods for determining wavelength were investigated: the Morlet wavelet, the Fourier transform, and the semivariogram. When applied to several hypothetical signals similar to those observed in petrophysical measurements in hydrocarbon reservoirs, all three methods could identify the presence of cyclicity. Only the wavelet scalogram, however, gave a clear indication of when the cyclic element was present and where frequency changes occurred in the signal. To illustrate the wavelet analysis, we processed well log and core data from a well in the Ormskirk Sandstone and determined the wavelet coefficients for each zone and the wavelengths of the strongest cyclicities. The cyclicities observed corresponded well with sedimentary features of the formation (e.g., channels and channel sets). Also, ratios of the cyclicity wavelengths corresponded with ratios of the Milankovitch precession, obliquity, and eccentricity periods. This result is in agreement with other investigators, who have proposed that Milankovitch-driven climate changes exercised an important control on Ormskirk Sandstone deposition.

The Eagle Ford Shale Play, South Texas: Regional Variations in Fluid Types, Hydrocarbon Production and Reservoir Properties

The Eagle Ford Shale is one of the most active U.S. shale plays; it produces oil, gas condensate, and dry gas. To better understand the regional and vertical variations of reservoir properties and their effects on fluid types and well performance, we conducted an integrated, regional study using production and well log data. Maps of the average gas-oil ratio (GOR) of the first three production months identified four fluid regions, including black oil, volatile oil, gas condensate, and dry gas regions. Maximum oil production occurs in Karnes County, where first-month oil production of most wells exceeds 5,000 barrels (bbl). The most productive gas region is between the Stuart City and Sligo Shelf Margins, where first-month gas production of most wells exceeds 60 million cubic feet (MMcf). Eagle Ford Shale petrophysical properties were analyzed in individual wells and were mapped to clarify the regionally variations of Eagle Ford Shale reservoir properties and their controls on fluid types and well performance. In comparison to the upper Eagle Ford, the lower Eagle Ford Shale has high gamma ray, high resistivity, low density, and long transit time values; we infer that the lower Eagle Ford shale has higher total organic carbon and lower carbonate content than the upper Eagle Ford Shale. Integration of production and geological data shows that thermal maturity and structural setting of the Eagle Ford Shale strongly influence fluid types and production rates. Plots of GOR vs. time for individual wells were constant in different reservoir fluids. Results of this study clarify causes of vertical and lateral heterogeneity in the Eagle Ford shale and the regional extents of fluid types. Understanding of the reservoir property differences between upper and lower Eagle Ford Shale should assist with optimizing completion design and stimulation strategies. The results may be applicable to similar developing shale plays.

PRISE: Petroleum Resource Investigation Summary and Evaluation

PRISE: Petroleum Resource Investigation Summary and Evaluation. (August 2008) Sara Old, B.S., Texas A&M University Chair of Advisory Committee: Dr. Stephen Holditch As conventional resources are depleted, unconventional gas (UG: gas from tight sands, coal beds, and shale) resources are becoming increasingly important to U.S and world energy supply. The volume of UG resources is generally unknown in most international basins. However, in 25 mature U.S. basins, UG resources have been produced for decades and are well characterized in the petroleum literature. The objective of this work was to develop a method for estimating recoverable UG resources in target, or exploratory, basins. The method was based on quantitative relations between known conventional and unconventional hydrocarbon resource types in mature U.S. basins. To develop the methodology to estimate resource volumes, we used data from the U.S. Geological Survey, Potential Gas Committee, Energy Information Administration, National Petroleum Council, and Gas Technology Institute to evaluate relations among hydrocarbon resource types in the Appalachian, Black Warrior, Greater Green River, Illinois, San Juan, Uinta-Piceance, and Wind River basins. We chose these seven basins because they are mature basins for both conventional and unconventional

Basin Analog Investigations Answer Characterization Challenges of Unconventional Gas Potential in Frontier Basins

To meet the global energy demand of the coming decades, the energy industry will need creative thinking that leads to the development of new energy sources. Unconventional gas resources, especially those in frontier basins, will play an important role in fulfilling future world energy needs. To develop unconventional gas resources, we must first identify their occurrences and quantify their potential. Basin analog assessment is a technique that can be used to rapidly and inexpensively identify and quantify potential unconventional gas resources. We have developed a basin analog methodology that is useful for rapidly and consistently evaluating the unconventional hydrocarbon resource potential in exploratory basins. The center of this approach is computer software, Basin Analog Systems Investigation (BASIN), which is used to identify analog basins. This software is linked to a database that includes geologic and petroleum systems information from intensely studied North America basins that contain well characterized conventional and unconventional hydrocarbon resources. To test BASIN, we selected 25 basins in North America that have a history of producing unconventional gas resources and began populating the database with critical data from these basins. These North American basins are “reference” basins that will be used to predict resources in other North American or international “target” or exploratory basins. The software identifies and numerically ranks reference basins that are most analogous to the target basin for the primary purpose of evaluating the potential unconventional resources in the target basin. We validated the software to demonstrate that it functions correctly, and we tested the validity of the process and the database. Accuracy of the results depends on the level of detail in the descriptions of geologic and petroleum systems. Finding a reference basin that is analogous to a frontier basin may provide critical insights into the frontier basin. Our method will help predict the unconventional hydrocarbon resource potential of frontier basins, guide exploration strategies, provide insights to reservoir characteristics, and help engineers make preliminary decisions concerning the best practices for drilling, completion, stimulation and production.Copyright

Probabilistic Assessment of World Recoverable Shale Gas Resources

Many shales previously thought of as only source rocks are now recognized as self-sourcing reservoirs that contain large volumes of natural gas and liquid hydrocarbons that can be produced using horizontal drilling and hydraulic fracturing. However, shale gas resources and development economics are uncertain, and these uncertainties beg for a probabilistic solution. Our objective was to probabilistically determine the distribution of technically recoverable resources (TRR) and shale original gas in place (OGIP) in highly uncertain and risky shale gas reservoirs for seven world regions. To assess technically recoverable resources, we used the distribution of recovery factors from shale gas reservoirs. We developed a software, Unconventional Gas Resource Assessment System (UGRAS), which integrates Monte Carlo simulation with an analytical reservoir simulator to establish the probability distribution of OGIP and TRR. We used UGRAS to evaluate the most productive shale gas plays in the United States, including the Barnett, Eagle Ford, Marcellus, Fayetteville, and Haynesville shales, and derived a representative distribution of recovery factors for shale gas reservoirs. The recovery factors for the five shale gas plays follow a general Beta distribution with a mean value of 25%. Finally, we extended the distribution of recovery factors gained from our analyses of shale gas plays in the U.S. to estimate technically recoverable shale-gas resources for the seven world regions. Total technically recoverable shale gas resources are estimated to range from 4,000 Tcf (P90) to 24,000 Tcf (P10). UGRAS is a robust tool that may be used to evaluate and rank shale-gas resources worldwide. This work provides important statistics for the five most productive shale-gas plays in the United States. Results of this work verify the existence of significant technically recoverable shale gas resources worldwide and can help industry better target its exploitation efforts in shale-gas plays.

CO2 SEQUESTRATION POTENTIAL OF TEXAS LOW-RANK COALS

The objectives of this project are to evaluate the feasibility of carbon dioxide (CO{sub 2}) sequestration in Texas low-rank coals and to determine the potential for enhanced coalbed methane (ECBM) recovery as an added benefit of sequestration. The main objectives for this reporting period were to perform reservoir simulation and economic sensitivity studies to (1) determine the effects of injection gas composition, (2) determine the effects of injection rate, and (3) determine the effects of coal dewatering prior to CO{sub 2} injection on CO{sub 2} sequestration in the Lower Calvert Bluff Formation (LCB) of the Wilcox Group coals in east-central Texas. To predict CO{sub 2} sequestration and ECBM in LCB coal beds for these three sensitivity studies, we constructed a 5-spot pattern reservoir simulation model and selected reservoir parameters representative of a typical depth, approximately 6,200-ft, of potential LCB coalbed reservoirs in the focus area of East-Central Texas. Simulation results of flue gas injection (13% CO{sub 2} - 87% N{sub 2}) in an 80-acre 5-spot pattern (40-ac well spacing) indicate that LCB coals with average net thickness of 20 ft can store a median value of 0.46 Bcf of CO{sub 2} at depths of 6,200 ft, with a median ECBM recovery of 0.94 Bcf and median CO{sub 2} breakthrough time of 4,270 days (11.7 years). Simulation of 100% CO{sub 2} injection in an 80-acre 5-spot pattern indicated that these same coals with average net thickness of 20 ft can store a median value of 1.75 Bcf of CO{sub 2} at depths of 6,200 ft with a median ECBM recovery of 0.67 Bcf and median CO{sub 2} breakthrough time of 1,650 days (4.5 years). Breakthrough was defined as the point when CO{sub 2} comprised 5% of the production stream for all cases. The injection rate sensitivity study for pure CO{sub 2} injection in an 80-acre 5-spot pattern at 6,200-ft depth shows that total volumes of CO{sub 2} sequestered and methane produced do not have significant sensitivity to injection rate. The main difference is in timing, with longer breakthrough times resulting as injection rate decreases. Breakthrough times for 80-acre patterns (40-acre well spacing) ranged from 670 days (1.8 years) to 7,240 days (19.8 years) for the reservoir parameters and well operating conditions investigated. The dewatering sensitivity study for pure CO{sub 2} injection in an 80-acre 5-spot pattern at 6,200-ft depth shows that total volumes of CO{sub 2} sequestered and methane produced do not have significant sensitivity to dewatering prior to CO{sub 2} injection. As time to start CO{sub 2} injection increases, the time to reach breakthrough also increases. Breakthrough times for 80-acre patterns (40-acre well spacing) ranged from 850 days (2.3 years) to 5,380 days (14.7 years) for the reservoir parameters and well injection/production schedules investigated. Preliminary economic modeling results using a gas price of

Global Unconventional Gas Resource Assessment

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Evaluation of the Technical and Economic Feasibility of CO2 Sequestration and Enhanced Coalbed Methane Recovery in Texas Low-Rank Coals

8 per Mscf and CO{sub 2} credits of

Global Unconventional Gas Resource Assessments

1.33 per ton CO{sub 2} indicate that injection of flue gas (87% N{sub 2}-13% CO{sub 2}) and 50% N{sub 2}-50% CO{sub 2} are more economically viable than injecting 100% CO{sub 2}. Results also indicate that injection rate and duration and timing of dewatering prior to CO{sub 2} injection have no significant effect on the economic viability of the project(s).