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116 records · Page 7Linked to original sources

Zone identification and oil saturation prediction in a waterflooded field: Residual oil zone, East Seminole Field, Texas, Permian Basin

Recently, the miscible CO 2 -EOR tertiary process used in the main pay zone (MP) of suitable reservoirs has broadened to include exploitation of the underlying residual oil zone (ROZ) where a significant amount of oil may remain. The objective of this study is to identify the ROZ and to assess the remaining oil in a brownfield ROZ by using core data and conventional well logs with probabilistic and predictive methods. Core and log data from three wells located in the East Seminole Field in Gaines County, Texas, were used to identify the MP and ROZ in the San Andres Limestone, and to predict oil saturations. The core measurements were used to calculate probabilistic in-situ oil saturations within the MP and the ROZ as a function of depth. Well logs, in combination with core data and calculated saturations, on the other hand, were used to develop two expert systems using artificial neural networks (ANN); one to identify the ROZ and MP, and the other to predict oil saturation. These systems were also supported by a classification and regression tree (CART) analysis to delineate the rules that lead to classifications of zones. Results showed that expert systems developed and calibrated by combining core and well log data can identify MP and ROZ with a success score of more than 90%. Saturations within these zones can be predicted with a correlation coefficient of around 0.6 for testing and 0.8 for training data. The analyses showed that neutron porosity and density well log readings are the most influential ones to identify zones in this field and to predict oil saturations in the MP and ROZ. To explain the relationships of input data with the results, a rule-based system was also applied, which revealed the underlying petrophysical differences between MP and ROZ. This new predictive approach using machine learning techniques, could potentially address the challenges that previous studies have come up against in defining the ROZ within the formation and quantifying remaining oil saturations. The method can potentially be applied to additional fields and help reliably identify the ROZ and estimate saturations for future resource evaluations.

Texas

Gas shale in the Rocky Mountains and beyond

This guidebook includes papers on various aspects of resource evaluation, exploration, petrophysics, reservoir potential, well deliverability and drilling and completion technology. As new shale plays are explored for and developed, it is important to learn from analogs and case histories, including those from outside the Rocky Mountain region. While the emphasis is on natural gas, we realize there is also value in learning from our experiences from shales and other fine-grained source rocks that have produced oil from Rocky Mountain basins.

Book

Carbon dioxide enhanced oil recovery and residual oil zone studies at the U.S. Geological Survey

The U.S. Geological Survey (USGS) is preparing a national resource assessment of the potential hydrocarbons recoverable after injection of carbon dioxide (CO2) into conventional oil reservoirs in the United States. The implementation of CO2-enhanced oil recovery (CO2-EOR) techniques can increase hydrocarbon production, and lead to incidental retention of CO2 in reservoir pore space allowing long-term storage of anthropogenic CO2. A Comprehensive Resource Database (CRD) containing proprietary data on location, geologic, petrophysical, and reservoir parameters, plus production and well counts for major oil and gas reservoirs in onshore areas and State waters of the conterminous United States and Alaska, was developed to support the USGS assessment. Residual oil zones (ROZs) also can provide potential pore space for long-term storage of anthropogenic CO2. However, ROZs are not included in the upcoming USGS national CO2-EOR assessment because assessment methods for ROZs still are being developed. Additional ROZ CO2-EOR and CO2 retention data and reservoir simulations are needed to calibrate national ROZ assessment estimates.

Conference Paper

Geology and assessment of undiscovered oil and gas resources in Mesozoic (Jurassic and Cretaceous) rocks of the onshore and state waters of the Gulf of Mexico Region, U.S.A

The U.S. Geological Survey (USGS) is in the final phase of the most recent assessment of the undiscovered technically recoverable oil and gas resources of the U.S. Gulf of Mexico coastal plain and state waters. Ongoing geologic, geochemical, and petrophysical framework studies have defined the total petroleum systems and assessment units (AUs) in the Gulf Coast region. Current studies examine the Mesozoic (Jurassic and Cretaceous) source rocks and reservoir units, and recent studies have assessed the undiscovered resources in Tertiary and certain Jurassic and Cretaceous units. The Upper Jurassic and Lower Cretaceous Cotton Valley Group and Lower Cretaceous Hosston and Travis Peak formations, as well as the Upper Cretaceous Taylor and Navarro groups and the Tuscaloosa and Woodbine groups downdip shelf-margin deltas, were assessed in 2006. Tertiary strata were assessed in 2007. Jurassic strata presently under evaluation include the Upper Jurassic Norphlet, Smackover, Haynesville, and Bossier formations. Lower Cretaceous units to be assessed in the present study include the Knowles Limestone, Sligo Formation, Trinity Group, Fredericksburg Group, and lower part of the Washita Group. Upper Cretaceous rocks being assessed include the Buda Limestone of the Washita Group, Eagle Ford Group (Eagle Ford shale, and the updip Tuscaloosa and Woodbine groups), Austin Chalk (Group), and Tokio and Eutaw formations. For each AU, a geologic model is developed to define hydrocarbon source, charge, migration, trap, and reservoir, and to estimate technically recoverable undiscovered oil and gas resources. The USGS assessment is focused on evaluating conventional clastic and carbonate deposystems, as well as resource volumes in emerging unconventional gas, shale gas, and shale oil plays currently attracting global attention.

Texas, Louisiana, Alabama, Mississippi, Florida

Object-based inversion of crosswell radar tomography data to monitor vegetable-oil injection experiment

Crosswell radar tomography methods can be used to dynamically image ground-water flow and mass transport associated with tracer tests, hydraulic tests, and natural physical processes. Dynamic imaging can be used to identify preferential flow paths and to help characterize complex aquifer heterogeneity. Unfortunately, because the raypath coverage of the interwell region is limited by the borehole geometry, the tomographic inverse problem is typically underdetermined, and tomograms may contain artifacts such as spurious blurring or streaking that confuse interpretation. We implement object-based inversion (using a constrained, non-linear, least-squares algorithm) as an alternative to pixel-based inversion approaches that utilize regularization (such as damping or smoothing criteria). Our approach requires pre- and post-injection travel-time data. Parameterization of the image plane comprises a small number of objects rather than a large number of pixels, resulting in an overdetermined problem that reduces the need for prior information. The nature and geometry of the objects are based on hydrologic insight into aquifer characteristics, the nature of the experiment, and the planned use of the geophysical results. The object-based inversion approach is demonstrated using synthetic and crosswell radar field data acquired during vegetable-oil injection experiments at a site in Fridley, Minnesota. The region where oil has displaced ground water is discretized as a stack of rectangles of variable horizontal extents. The inversion provides the geometry of the affected region and an estimate of the radar slowness change for each rectangle. Applying petrophysical models to these results and porosity from neutron logs, we estimate that the vegetable-oil emulsion saturation in various layers ranges from 60 to 90%. Further work is needed to assess the accuracy of the emulsion saturation estimates. Using synthetic- and field-data examples, the object-based inversion approach is shown to be an effective strategy for inverting crosswell radar tomography data acquired to monitor the emplacement of vegetable-oil emulsions. A principal advantage of object-based inversion is that it yields images that hydrologists and engineers can easily interpret and use for model calibration.

Conference Paper

Geohydrologic and water-quality characterization of a fractured-bedrock test hole in an area of Marcellus Shale gas development, Sullivan County, Pennsylvania

The stratigraphy, water-bearing zones, and quality of groundwater were characterized in a 1,400-ft-deep test hole drilled during 2013 in fractured bedrock in Sullivan County, Pa., by collection and analysis of measurements made during drilling, geophysical logs, and depth-specific hydraulic tests and water samples. The multidisciplinary characterization of the test hole was a cooperative effort between the Pennsylvania Department of Natural Resources, Bureau of Geological Survey (BGS), and the U.S. Geological Survey (USGS). The study provided information to aid the bedrock mapping of the Laporte 7.5-minute quad-rangle by BGS to help quantify the depth and character of fresh and saline groundwater in an area of shale-gas exploration (described in this report), which could help gas operators protect groundwater resources. The Laporte test hole was drilled with air-hammer methods in an upland setting in the headwaters of Loyalsock Creek in the Glaciated High Plateau section of the Appalachian Plateaus physiographic province. Bedrock residuum and till were penetrated from land surface to 8.5 ft, the Huntley Mountain Formation of Mississippian and Devonian age was penetrated from 8.5 to 540 ft, and the Catskill Formation of Devonian age was penetrated from 540 to 1,400 ft. Fractures, determined from optical televiewer, acoustic televiewer, and video logs, were commonly encountered to 200 ft bls (below land surface), then decreased exponentially with depth, except at a highly fractured zone from 637 to 644 ft bls. Most fractures were along bedding planes and had a strike of about 243 degrees and dip about 4 degrees to the northwest, consistent with the test-hole location on the north limb of the Muncy Creek anticline. Few fractures were noted below 650 ft. The depths of fresh and saline water-bearing fracture zones were identified in the test hole by geophysical-log analysis and were verified by pumping samples from zones isolated with packers and by collecting samples in the open hole with a wire-line point sampler. Six water-bearing zones associated with single or multiple fractures were identified at depths of 130–135, 180, 267–275, 425, 637–644, and 1,003 ft bls. Under ambient conditions, fresh water entered the hole from fractures at 130-135 and 180 ft bls, flowed downward and exited at fractures from 267–275, 425, and 637–644 ft. When pumped at 16.2 gal/min, most of the water from the open test hole was contributed from the fracture at 180 ft bls. Transmissivity, estimated from analysis of the specific-capacity data and flowmeter logs, is about 850 ft 2 /d for the entire open hole, and about 60 percent of the transmissivity is contributed from the fracture zone at 180 ft bls. The hydraulic heads in the deep water-bearing zones at 425 and 637–644 ft were about 100 ft lower than hydraulic heads in shallow water-bearing zones at 180 ft bls and above, indicating a large downward vertical hydraulic gradient. Water samples pumped from fracture zones isolated by packers at and above the water-bearing zone at 450 ft bls were fresh with dissolved-solids contents of 105 mg/L or less. The sample isolated at 637–644 ft bls was probably affected by leakage around packers, but the specific-conductance samples collected during drilling that were believed to be representa-tive of the fracture zone at 637–644 ft bls indicated slightly saline water. Below the 637–644 ft zone, a flowmeter log in the open hole did not detect any vertical flow, and the temperature log approached the geothermal gradient, indicating little ambient fluid flow and minimal fracture transmissivity below this depth. A petrophysical-log analysis using estimates of formation water resistivity from Archie’s Equation indicated an apparent transition from fresh to saline water in the sandstones occurs between 450 to 900 ft bls, with saline water indicated below 900 ft. Small seeps of saline water were delineated at 958, 989, and 1,003 ft bls by a time series of specific-conductance logs, and a discrete-point water sample at 990 ft bls with total dissolved-solids concentration of 19,900 mg/L verified that highly saline water was present below 900 ft bls. Occurrence of saline water at a depth of about 900 ft bls is below altitude of streams within 3 to 5 miles of the test hole but is about 930 ft above the altitude at the mouth of Loyalsock Creek where is enters the West Branch Susquehanna River at Montours-ville, Pa. The depth to saline water in this test hole is close to depths estimated at two other deep test holes drilled by the BGS in upland settings in Bradford and Tioga Counties in north-ern Pennsylvania. The saline water from 990 ft bls had a chemical composition similar to Appalachian Basin brines that had been diluted with fresh water. Predominant ions in the saline water were sodium, chloride, and calcium. Trace constituents of strontium, bromide, barium, lithium, and molybdenum were all more than 5,000 times greater than in freshwater samples from 167 or 270 ft bls. Methane concentration in the saline water sample from 990 ft was 120 mg/L. The concentration ratios of methane to higher-chain hydrocarbon gases and isotopic ratios of 13 C/ 12 C and 2 H/ 1 H of methane indicate that the gases are likely of thermogenic origin. In the sample from 990 ft bls, the 13 C/ 12 C of methane was less negative (-34.81 per mil) than 13 C/ 12 C of ethane (-37.1 per mil). Isotopic reversals such as this are generally found in gases from rocks older than the Catskill Formation, so its recognition in a natural upland setting at relatively shallow depth could be important when interpreting isotopic results to identify the origin of stray gas in the area.

Pennsylvania

Quantitative modeling of secondary migration: Understanding the origin of natural gas charge of the Haynesville Formation in the Sabine Uplift area of Louisiana and Texas

The Upper Jurassic (Kimmeridgian) mudstones of the Haynesville Formation in the Sabine Uplift, Louisiana and Texas, are widely considered to be a self-sourced natural gas reservoir; however, additional sources of gas may have charged the mudstones in the Louisiana portion of the uplift. Secondary migration of hydrocarbons into the Sabine Uplift from downdip, gas-generating Jurassic source rocks in the North Louisiana Salt Basin was quantitively modeled in this study. Jurassic source rocks include the Smackover, Haynesville, and Bossier Formations. Thermodynamic equations of state were used to determine thermophysical properties of supercritical methane and water under reservoir conditions. A time-dependent derivation of Darcy’s Law for pressure-driven laminar fluid flow through porous media was used to model secondary migration at reservoir conditions. This study indicates secondary migration requires approximately 100,000 yr for pore fluids to migrate through 1.0 km of carrier beds having representative petrophysical, fluid, and reservoir properties of the Haynesville Formation. As an example migration pathway, the distance from the middle of the North Louisiana Salt Basin to the center of the Sabine Uplift is approximately 96 mi (155 km). Given migration velocities over this distance, 15.5 m.y. is required for hydrocarbons to migrate from the North Louisiana Salt Basin and charge the Haynesville Formation in the Sabine Uplift. This study also indicates supercritical water is 6 times more thermally conductive than methane under reservoir conditions; however, the relatively small volumes of migrated water likely did not transfer sufficient heat for the metagenesis of methane. Based on this study, a component of natural gas charging the Haynesville Formation of the Sabine Uplift area can reasonably be explained by lateral migration and hydrodynamic flow from thermally mature Jurassic source rocks located in adjacent basins.

Louisiana, Texas

Nuclear magnetic resonance logging of a deep test well for estimation of aquifer and confining-unit hydraulic properties, Long Island, New York

A 1,200-foot deep well in southwestern Nassau County, Long Island, N.Y. was selected to evaluate the application of a nuclear magnetic resonance (NMR) logging tool. Technological advances in NMR borehole systems have allowed for reduced probe length and diameter, and focused measurement at specific diameters beyond the disturbed zone surrounding a well. This 3-inch-diameter NMR tool was specifically developed for use in deep 4-inch-diameter polyvinyl chloride cased wells common to Long Island. Selected intervals of the Magothy and Lloyd aquifers and the Raritan confining unit were logged for the evaluation. Unlike other petrophysical logs that respond to the rock matrix and fluid properties and are strongly dependent on mineralogy, NMR logs respond to the presence of hydrogen protons in the formation fluid to determine water fraction and pore-size distribution. NMR log analysis provided estimates of the clay-bound, capillary-bound, and mobile water fraction and hydraulic conductivity of aquifers and confining units penetrated by the well. NMR-estimated porosity and mobile water fraction for the Magothy aquifer (0.34 and 0.22 respectively), Magothy/Raritan(?) (0.35 and 0.30), Raritan confining unit (0.30 and 0.13), Raritan clay and silt (0.23 and 0.01), and the Lloyd aquifer (0.27 and 0.19) was determined from the NMR log. Hydraulic conductivity was estimated from the NMR-log data using the Schlumberger- Doll Research and sum of squared echoes equations with empirically derived constants for unconsolidated aquifers. Average hydraulic conductivity of the Magothy aquifer was 70 ft/d, the Raritan confining unit was 9.0 ft/d overall, the clay-rich lower part 0.24 ft/d, and the Lloyd aquifer was 56 ft/d. The coarse sandy Magothy/Raritan(?) unit between the Magothy aquifer and the top of the Raritan confining unit had the highest hydraulic conductivity of 345 ft/d. The hydraulic-conductivity estimates from the NMR log analysis for the Magothy and Lloyd aquifers were consistent with published values and that estimated for the Lloyd aquifer from a specific-capacity test at the well site.

New York