There is increasing interest in drilling the Austin Chalk formation, with hopes that the latest unconventional development methods can deliver a boom in a play that has seen several over a 90-year history. The Austin Chalk play could go through a revival if the industry can view the formation through “a fresh set of eyes,” says EnerVest’s Tony Maranto.
The chief upstream strategist of IHS Markit said in a recent presentation that oil exploration must improve its ability to deliver value and better communicate that value to the financial community. New ways of thinking about exploration opportunities are needed. Producers in Oklahoma’s newly opened Merge play are sitting atop a resource that rivals some major world gas fields and discoveries, Citizen Energy’s Geology CEO Greg Augsburger told the SPE Gulf Coast Section Business Development Group recently. The Austin Chalk play could go through a revival if the industry can view the formation through “a fresh set of eyes,” says EnerVest’s Tony Maranto. Dimethyl-ether (DME) -enhanced waterflood (DEW) is a process in which DME is added to injection water and, upon injection, preferentially partitions into the remaining oil.
Different factors are involved at each stage within the overall constraints of optimum reservoir penetration. Most directional wells are drilled from multiwell installations, platforms, or drillsites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved. At the start of the well, the overriding constraint on the well path is the presence of other wells.
Horizontal wells are high-angle wells (with an inclination of generally greater than 85) drilled to enhance reservoir performance by placing a long wellbore section within the reservoir. Horizontal Well contrasts with an extended-reach well, which is a high-angle directional well drilled to intersect a target point. There was relatively little horizontal drilling activity before 1985. The Austin Chalk play is responsible for the boom in horizontal drilling activity in the U.S. Now, horizontal drilling is considered an effective reservoir-development tool. Horizontal wells are normally characterized by their buildup rates and are broadly classified into three groups that dictate the drilling and completion practices required, as shown in Table 1.
Geochemical data measured on oil samples produced from wells landed in the Austin Chalk, the Eagle Ford Formation, and the Buda Formation and on petroleum samples sequentially extracted from Upper Eagle Ford and Lower Eagle Ford marl and calcareous shale core pucks using several solvents were used to estimate the amount and properties of producible oil, immobile adsorbed/dissolved oil, and non-producible bitumen in those core samples. Crushed core samples obtained from two monitor wells located on the San Marcos Arch where Eagle Ford source-rock beds have reached different levels of maturity were sequentially extracted using a weak solvent (cyclohexane; CH), two stronger solvents (toluene and DCM), and a very strong solvent (chloroform-methanol; CM). Similar geochemical data were measured on the core extracts (after heating them to evaporate the solvents), and on native and topped oil samples. The CH extracts exhibit n-alkane profiles characteristic of crude oil, but extracts obtained using stronger solvent do not resemble oil. C15-C35 HC compounds present in produced oils are more abundant in CH extracts (which principally contain producible oil and adsorbed/dissolved oil) than in extracts obtained using stronger solvents (which principally contain bitumen). The SARA composition of topped oil samples also is more similar to the composition of core extracts obtained using CH than extracts obtained using stronger solvents (which contain significantly more resins and asphaltenes). The extract obtained from lower-maturity marl core pucks using CH contains much more sulfur (≈4.4 wt%) than the CH extract obtained from more thermally mature marl core pucks (≈2.0 wt%). Calibrations between the API gravity, C7 temperature, and sulfur content of native and topped oil samples were used to estimate the gravity and sulfur content of core extracts obtained using different solvents. The amount of resin-rich immobile oil in the core extracts was estimated using reasonable assumptions about the composition of that component. The Lower Eagle Ford marl at the higher-maturity monitor well contains ≈0.35 wt% of ≈30-31°API producible oil and ≈0.27 wt% of non-producible bitumen. That reservoir contains only ≈0.12 wt% of ≈27°API producible oil and ≈0.38 wt% of non-producible bitumen at the lower-maturity monitor well. The LEF calcareous shale contains approximately the same amount of producible oil as the overlying marl at the more mature monitor well, but it contains much less non-producible bitumen (≈0.12 wt%).
Objectives/Scope: The continuous drive by the E&P industry to deliver additional value and performance improvements in unconventional reservoirs has created the need for innovative advances in technology to meet evolving challenges. Jweda et al. (2017) and Liu et al. (2017) developed a novel time-lapse geochemistry technology calibrated to core extracted oils to cost effectively ascertain vertical drainage, which is among the most critical parameters used in determining optimal field development strategies. Aqueous geochemistry, well-established in academic and environmental investigations, is another technology that can be used in conjunction with time-lapse hydrocarbon geochemistry to evaluate drainage behavior, vertical connectivity between stacked wells and to ascertain the efficacy of different stimulation designs. Methods/Procedures/Process: More than 300 produced water samples from approximately 60 different Eagle Ford wells have been collected across ConocoPhillips’ Eagle Ford acreage. Sampling campaigns have included collecting several long-term time-series and baseline samples from individual wells across the field. The analytical program consists of a suite of total ion chemistry (cations and anions), salinity, alkalinity, and isotopic geochemistry (δ18O, δD, 87Sr/86Sr, δ11B). Results/Observations/Conclusions: Produced waters, contain a robust arsenal of geochemical signals that can be analyzed to understand the provenance(s) and change(s) in composition with time of these produced waters. A combination of interpretative and multivariate statistical tools were used to gain a deeper understanding of water-rock interactions and mixing/diffusion processes in the subsurface. Stimulation water was differentiated from in-situ formation water, and the evolution of that process was tracked over time. Time-series water analyses were also used to evaluate differences between completion designs, determine the vertical drainage and/or communication between wells, and ultimately understand the drained rock volume through time. Applications/Significance/Novelty: We clearly demonstrate that produced waters are mixtures of stimulation and formation water and that long-term geochemical signals from different layers within the Eagle Ford can be differentiated using aqueous geochemistry. Furthermore, we show that the formation waters vary vertically, coincident with hydrocarbon indicators (oil biomarkers and gas isotopes). To our knowledge, this is among the first published studies of aqueous geochemical behavior of produced waters in the Eagle Ford and the first to establish that intra-formational waters can be discerned, which is particularly novel and important for evaluating completion designs and strategies within a stacked development.
The expansion of unconventional petroleum resource exploration and production in the United States has led to an increase in source rock characterization efforts, particularly related to bulk organic and mineralogical properties. To support the analytical and research needs of industry and academia, as well as internal work, the U.S. Geological Survey (USGS) has collected and prepared shale geochemical reference materials (GRMs) from several major shale petroleum systems in the U.S. The sources of these materials are the Late Cretaceous Boquillas (lower Eagle Ford-equivalent) Formation (roadcut near Del Rio, TX), Late Cretaceous Mancos Shale (outcrop near Delta, CO), Devonian–Mississippian Woodford Shale (outcrop near Ardmore, OK), Late Cretaceous Niobrara Formation (quarry near Lyons, CO), Middle Devonian Marcellus Shale (creek bed in LeRoy, NY), and Eocene Mahogany zone oil shale of the Green River Formation (oil shale mine near Rifle, CO). Of particular interest in the development of these GRMs has been the examination of variability between laboratories and specific methods or instruments in commonly made measurements, including major- and trace-element concentrations, X-ray diffraction (XRD) mineralogy, total organic carbon (TOC) content, and programmed pyrolysis (PP) parameters. For the component concentrations and parameters we measured, the techniques and instrument types included: (1) elemental analysis by X-ray fluorescence, inductively coupled plasma mass spectrometry, and instrumental neutron activation analysis; (2) XRD mineralogy with various preparatory methods (spray drying or micronizing with or without internal standard); (3) TOC by combustion with infrared detection after carbonate removal or the PP approach; (4) PP by Rock-Eval 2 or more recently developed instruments (Rock-Eval 6, Source Rock Analyzer or SRA, and Hydrocarbon Analyzer With Kinetics or HAWK). Overall, the results showed that the selected shales cover a wide range of source rock organic and mineralogical properties. Major- and trace-element chemistry results showed low heterogeneity consistent with other USGS GRMs. Comparison of TOC results showed coefficients of variation (COV) of around 5% and the most consistent organic geochemical results between different laboratories and methods. Arguably the most relevant PP measurement, S2 or kerogen hydrocarbon-generating potential (mg-HC/g-rock), showed a somewhat wider range of variability than TOC (COV ~10%), but was consistent between the three modern instruments and the industry-standard Rock-Eval 2. Major phase mineralogy (mineral concentrations ≥10 wt. %, organic-free basis) were comparable between laboratories, but variability in minor phase identification and quantification was observed. Utilization of these shale GRMs as quality control samples and testing materials is expected to help support analytical and experimental efforts in the continued development of unconventional petroleum resources.
The definition of unconventional reservoirs continues to evolve over time as advances in technology make it more viable to extract hydrocarbons. The need for reservoir characterization in such reservoirs, however, will continue to increase to optimize wellbore placement and enhance production. For high-angle or horizontal wellbores common in unconventional drilling, obtaining information from wireline technologies may be either too expensive or risky, although obtaining a wellbore stability assessment while drilling provides a key input into the real-time geomechanical model. This paper presents field test results of a new 4¾-in. ultrasonic imaging logging-while-drilling (LWD) tool that provides a real-time assessment of borehole shape and high-resolution caliper and acoustic impedance images in both water-based mud (WBM) and oil-based mud (OBM) applications.
Images from measurements, such as gamma ray, resistivity, or density, are common in LWD applications. However, high-resolution images have historically been limited to WBM applications. This paper describes the sensor physics and tool configuration that enable the acquisition of borehole caliper and acoustic impedance images in all mud types, with examples of logs obtained while drilling in boreholes using OBM. Details of the comparison with wireline data sets are also given.
Vertical and horizontal wellbores covering different lithologies are described, showing that high-resolution images are now available in slimhole OBM applications. Caliper images illustrate small changes in borehole shape, and impedance images can be used to evaluate geological features and determine stratigraphic dip. The evaluation of caliper data with a wireline multifinger caliper illustrates the potential to eliminate a separate wireline run before completing the well. Comparison of while-drilling data with tripping out of hole data provides crucial insight into wellbore deterioration with time.
The technology described addresses key challenges encountered while drilling and evaluating unconventional reservoirs. Real-time wellbore stability assessment enables optimization of drilling parameters and mud weight in all unconventional reservoirs. Identification of faults and fractures provides valuable information to optimize the hydraulic fracturing program in shale gas applications. Inputs into the geomechanical model are valuable in the assessment of tight sand reservoirs with extremely low porosity and permeability. Limestone reservoirs with minor shale content may require OBM to minimize wellbore deterioration with time. Monitoring such deterioration is critical in optimizing the placement of packers and the hydraulic fracturing program design.
Providing the industry's highest-resolution images in all mud types, even under high logging speeds represents a unique method of assessing real-time wellbore stability and enhancing formation evaluation in slim wellbores in unconventional reservoirs.
Kosanke, Tobi (Independent Consultant) | Loucks, Robert G. (The University of Texas at Austin) | Larson, Toti (The University of Texas at Austin) | Greene, James (TerraCore) | Linton, Paul (TerraCore)
Hyperspectral imaging (HI) is a method of observing and enhancing geological rock properties that are not readily apparent visually. Originally developed for the mining industry, HI uses a combination of short-wave infrared light (SWIR) and long-wave infrared light (LWIR) to create a visual ‘map’ of the minerals on the surface of a core that respond to reflectance principles. HI, which requires no special preparation other than that the core be slabbed, clean, and dry, can be rapidly obtained and provides mineralogical and chemical results related to various energy emitted in wavelength spectrum by either halogen bulb reflectance (short-wave quantification) or heat reflectance spectra (long-wavelength quantification).
We collected hyperspectral core imaging data of the Marathon 1 Austin Chalk Robert Todd core in central Louisiana to obtain detailed, high-resolution mineralogical and textural information and investigate the application of hyperspectral imaging as an integrative tool.
Digital HI-derived single mineral curves calibrated to X-ray diffraction (XRD) were imported as curves to display mineralogical variations with depth alongside overlays showing the textural relationships of the mineralogical assemblages, rock typing models, X-ray fluorescence (XRF) data, TOC data and rockmechanics data. The integration of the hyperspectral data with core description, SEM, thin-section, XRF, XRD, rock mechanics and TOC data illustrates relative differences in carbonate volumes that identify Milankovitch cycles, delineates fabric via variations in mineralogical composition of fine laminae, identifies relatively Sr-rich intervals that cannot be distinguished visually, reveals a relationship between total organic content and mineralogy, and facilitates upscaling of SEM and thin-section date to the core scale.
Eagle Ford shale in South Texas is a major oil and gas production play of in the US Gulf Coast region. While some attribute the successful well performance of Eagle Ford to the technology advancement such as horizontal drilling and hydraulic fracturing, others credit the role of geological settings. However, it is still unclear what the individual or combined effects from these two sides are. Data-driven approaches, including Partial Least Square (PLS), Random Forest (RF), and Deep Neural Network (DNN), reveal relationships among the production, geological settings, and completion strategies.
In this study, we considered six-month cumulative oil production as the well performance criterion for horizontal wells completed from 2015 to 2017. We selected completion parameters such as perforation length, proppant loading, and fluid volume. We selected structural depth, lower Eagle Ford Shale thickness, total organic carbon (TOC), number of limestone beds, and average bed thickness as the key geological controls on regional production.
We calculated Spearman correlation coefficients to detect correlated input parameters and applied Singular Value Decomposition (SVD) to identify redundant input parameters. Then we performed partial linear square (PLS) regression to predict the six-month oil production from geological and completion parameters. We then used random forest (RF) and deep neural network (DNN) as non-linear machine learning techniques to predict six-month oil production and compared the prediction accuracies for these techniques against the recorded well performance using the coefficient of determination and mean squared error as criteria. Last, we ranked the relative importance of each input parameter using RF and Minimum Redundancy Maximum Relevance (MRMR).
This paper first provides the rational of input variables selection. Then the construed model helps understand the effects of completion designs and geological variables on well productivity in the Eagle Ford. This might provide valuable information to help to make decisions for new well development. This concept can be generalized among other plays.