The Devonian-Mississippian STACK/SCOOP Play of the Oklahoma Anadarko Basin is a complex assemblage of tight carbonate and siliciclastic strata and an important oil and gas province. In the last decade, prolific drilling has demonstrated significant heterogeneity in the composition of oils produced from STACK/SCOOP reservoirs. This study discusses possible geoscientific explanations for the heterogeneity observed in produced oils and describes how source, maturation, and migration affect their composition.
Geochemical data from 136 produced oils across 12 counties from 4 producing reservoirs is reviewed. Calculated thermal maturity (Rc%) from alkylated polyaromatic compounds shows excellent agreement with oil thermal maturity increasing with increased depth. Oils produced from overpressured reservoirs exhibit a strong relationship between Rc% and Gas-Oil Ratio (GOR), while normal- to underpressured reservoirs exhibit GORs up to an order of magnitude higher at similar Rc%. Light hydrocarbons show that paraffinicity varies starkly with producing reservoir, suggesting compositional fractionation from diffusive migration through tight and argillaceous strata. Conversely, aromaticity varies geographically by Play Region, indicative of changing depositional environments and organic input across the basin. Isoprenoid and sesquiterpane biomarkers indicate all oils are generated by Type II or Type II/III mixed organic matter, but Springer Group reservoirs are charged by a highly argillaceous, non-Woodford source.
The Anadarko Basin is the deepest sedimentary basin in the cratonic interior of the North America with as much as 40,000 feet of Paleozoic sediments (Johnson, 1989). The Anadarko is an asymmetric basin with the deepest sediments bound against the Amarillo-Wichita Uplift to the southwest. The basin is elongated along its west-northwest axis and bound by the Nemaha Ridge to the east and the Anadarko shelf to the west and north.
In the last decade, drilling of Devonian-Mississippian strata along the margins of the basin have delineated one the continent's most successful petroleum resource plays. These areas are colloquially referred to as the
Swami, Vivek (CGG) | Tavares, Julio (CGG) | Pandey, Vishnu (CGG) | Nekrasova, Tatyana (CGG) | Cook, Dan (Bravo Natural Resources) | Moncayo, Jose (Bravo Natural Resources) | Yale, David (Yale Geomechanics Consulting)
In this study, a state-of-the-art seismic driven 3D geological model was built and calibrated to a petrophysical and geomechanical analysis, 1D-MEM (Mechanical Earth Model), on chosen wells within the Arkoma Basin of Oklahoma. The well information utilized in this study included basic wireline logs and core analysis, including XRD (X-Ray diffraction) data. The traditional petrophysical analysis was augmented with advanced rock physics and statistical techniques to generate the necessary logs. Hydrostatic, overburden and pore pressures were calculated with a petrophysical evaluation model. The 1D-MEMs were based on the Eaton/Olson/Blanton approach with the HTI (Horizontal Transverse Anisotropy) assumption. The 1D-MEMs were calibrated to laboratory data (triaxial tests) and field observations (mud logs, wellbore failure, frac pressures). Therefore, a very good confidence was achieved on Biot's coefficient, tectonic components, anisotropy and dynamic to static conversion factors for Young's Modulus and Poisson's Ratio. Seismic inversions were performed in different time windows and merged to generate high resolution P- and S-Impedance attributes from surface down to the target interval after careful AVO compliant gather preconditioning. A density volume estimate was calibrated to well data, accounting for different geological formations, to decouple P- and S-Wave components as a 3D volume, as well as dynamic Young's modulus (E) and Poisson's ratio (PR). Dynamic E and PR were converted to static parameters using results from 1D-MEMs; and 3D models of Biot's coefficient (α) and tectonic components were built to compute 3D fracture pressure volumes calibrated to well data. The final products were seismic-driven 3D pore pressure and fracture pressure calibrated to 1D-MEMs. The correlation between measured/estimated well logs and corresponding seismic-derived pseudo logs was more than 80%, which indicates good quality of seismic inversion results and hence 3D-MEM. Also, stress barriers, anisotropy, and brittleness indices were calculated on well scale which would help to identify best zones to place hydraulic fractures. The 3D geological model will aid in identifying sweet-spots and optimizing hydraulic fractures.
This paper presents detailed lithofacies identification from the I-35 Sycamore outcrop and predicts the rock properties from wireline logs to propose landing zones within the Mississippian Sycamore rocks in Southern Oklahoma. To achieve these objectives, three types of studies were conducted: (a) field studies (b) lab analysis, and (c) machine learning. In field studies, we measured the complete 450 ft Sycamore stratigraphic section on the south limb of the Arbuckle Mountains along I-35, measured the outcrop gamma-ray profile, calculated the fracture intensity per bed and restored the fracture orientations to the horizontal bedding plane. The contacts with the underlying Woodford Shale and overlying Caney Shale were additionally examined. Lab studies included petrographic analyses, Scanning Electron Microscopy (SEM), Rock Eval Pyrolysis analyses, and X-ray Diffraction (XRD). For machine learning studies, principal component analysis (PCA), elbow method, and self-organizing map (SOM) were used to analyze the electrofacies from the outcrop and an uncored well.
As a result, it was found that the outcrop stratigraphy, lithofacies and electrofacies are tied with the hand-held gamma ray profile and correlated with a nearby subsurface well. Five major outcrop lithofacies are identified from wireline logs. Two fracture sets (N18E and N63W) were observed in the outcrop. Fracture intensity varied from 1.5 to 8 fractures per linear ft. Most fractures are filled with calcite, but some contain bitumen. The Rock Eval Pyrolysis analyses revealed that the I-35 Sycamore intervals are dominated by apparent type II and type III kerogen (oil prone and oil/gas prone) with an average Tmax of 440 °C. Total organic matter ranged from 0.1 to 1.5 wt % in the outcrop.
The reservoir quality was assessed by integrating lithofacies, fracture analyses, and geochemical analyses. The bioturbated shale and/or the sandy siltstone can be a potential target zone for the following reasons: the bioturbated shale is characterized by the highest fracture abundances (avg. 4.4 fractures per linear ft), and clay content is 35%, with 50% quartz, indicating a somewhat brittle rock, with a potential hydrocarbon migration, during production, from the underlying Woodford shale during hydraulic fracturing. The sandy siltstone is characterized by the absence of calcite cement, highest micro-porosity, highest quartz (58%), and potential hydrocarbon migrations from the underlying upper shale section of Mississippian rocks and/or charged from the overlying Caney shale or the underlying Woodford shale. These two lithofacies and other lithofacies can be predicted from well log signatures when uncored wells are unavailable.
Sinkhole and vertical collapse features associated with paleokarst have been observed in Hughes and Coal counties of Oklahoma using 3D seismic data and attributes that enhance these features. Vertical pipe structures are interpreted as mature paleokarst collapse features originating below the Viola limestone extending upwards beyond the Mississippian Caney Shale and terminating in the Pennsylvanian Cromwell sandstone. These collapse features are coincident with sinkholes that have been characterized in the Viola. These pipes features are evident on time structure maps and are 700–1600 ft deep relative to uncollapsed formation tops, have diameters of 500–1700 ft and are 1500–7000 ft apart. We also observe circular features in the Pennsylvanian Wapanucka limestone on seismic amplitude which suggests the presence of immature paleokarst sinkholes that are not mappable on time structure. These Wapanucka circular features are mostly coincident with the vertical collapse features observed in the Viola limestone several thousand feet below.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 210A (Anaheim Convention Center)
Presentation Type: Oral
Welker, Carrie (Schlumberger Reservoir Laboratories) | Feiner, Sarah (Schlumberger Reservoir Laboratories) | Lishansky, Rachel (Schlumberger Reservoir Laboratories) | Phiukhao, Wipawon (Schlumberger Reservoir Laboratories) | Chao, Jiun-Chi (Schlumberger Reservoir Laboratories) | Moore, Russell (Schlumberger Reservoir Laboratories) | Hall, Don (Schlumberger Reservoir Laboratories)
Archived cuttings samples (n = 6713) from 58 wells located in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma (Figure 1; Table 1) were analyzed for their bulk trapped fluid content (fluid inclusions and other tightly held volatiles) via the fluid inclusion stratigraphy (FIS) technique. Fluid inclusion petrography (n = 300) and microthermometry (n = 58) analyses were also performed on selected intervals, based on FIS results. Data were used to evaluate the vertical and lateral distribution of hydrocarbons and non-hydrocarbon volatiles, oil gravities, phase state, salinity, and burial temperatures. The most prominent gas and liquid hydrocarbon FIS responses are recorded in the Caney to Viola sections. Both migrated and locally generated components are distinguished, and several episodes of migration may be documented within a given well. Overall, FIS oil/condensate responses and petrographic observations suggest a liquids-enhanced interval at 8,000–12,000 ft, although in some instances liquid petroleum zones extend to 15,000 ft. Gas-enrichment occurs to the west in response to increased thermal maturity, and sulfur species related to thermochemical sulfate reduction at high temperature occur towards the west and at depths >13,000 ft. Measured petroleum inclusions show mostly values of 38° to 45° API gravity. Most petroleum inclusions homogenize via bubble-point transition, and bubble-point temperatures suggest that they occur as undersaturated liquids at current reservoir conditions. Aqueous inclusion homogenization temperatures (Th) imply maximum burial temperatures that are generally higher than current temperatures, and probably reflect 3000–4000 ft of uplift since inclusion formation. Inclusion salinities are generally in the 1–5 weight percent NaCl-equivalent range suggesting brackish to evolved basin fluids. Independent measures of thermal maturity, including pyrolysis, Th of aqueous inclusions, and biomarkers, are in general agreement, and suggest that much of the recorded petroleum was proximally sourced. This historically productive region is attractive for unconventional reservoir development due to liquids potential and favorable economics. However, fluid characteristics can vary greatly over a relatively small area, resulting in significant differences in recovery from nearby wells. By analyzing fluid inclusions, it is possible to establish regional hydrocarbon potential with a small amount of unpreserved, archived drill cuttings and evaluate the likely production characteristics of fluids within a given area.
Zhang, Hao (Baker Hughes Incorporated) | Mendez, Freddy (Baker Hughes Incorporated) | Frost, Elton (Baker Hughes Incorporated) | McGlynn, Ian (Baker Hughes Incorporated) | Alarcon, Nora (Baker Hughes Incorporated) | Mezzatesta, Alberto (Baker Hughes Incorporated) | Quinn, Terry (Consultant) | Manning, Michael (Consultant)
The estimation of porosity, kerogen concentration, and mineral composition is an integral part of unconventional reservoir formation evaluation. Porosity and kerogen content are the main factors influencing the amount of hydrocarbon-in-place, while mineral composition affects hydraulic fracture generation and propagation. Unconventional resources such as shale plays are compositionally complex due to great variability in rock composition and post-depositional diagenetic processes. Consequently, a reliable method that integrates results from various logging tools and core analysis is needed to determine these key petrophysical properties.
Conventional well logs are typically acquired as a minimum logging program, providing geologists with the basic elements for tops identification and stratigraphic correlation. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by a minimum subset of minerals. In organic shale formations, these techniques often prove ineffective because conventional well logs are influenced to some degree by variations of mineralogy and porosity. Advanced geochemical logs, which are measurements that respond to capture and inelastic elemental composition of the rock and fluids using pulsed neutron technology, can help to understand this variability in mineralogy. This work introduces an inversion-based workflow based on probabilistic concepts to estimate total organic carbon (TOC), mineral concentrations, and porosity of shale formations using a combination of geochemical logs and conventional logs.
The workflow starts with the construction of a log-based deterministic mineral model including the most likely minerals based on available knowledge and core analyses. An iterative inversion process is then applied, based on the mineral model, to estimate mineral content and porosity in addition to considering formation complexity and data quality. Uncertainties derived for each logging tool along with borehole environmental factors are formally integrated into the solution. Validation of the proposed methodology is performed using actual field data sets. A field example is supplied from a Fayetteville shale play where the workflow was successfully implemented, along with a comparison with core measurements such as XRD, XRF, SEM, porosity and pyrolysis data. The comparison shows good agreement between TOC and mineralogy derived from logs and cores.
The proposed workflow integrating geochemical and conventional log measurements can reliably estimate the key petrophysical properties for unconventional reservoirs especially hydrocarbon-bearing shale. This method can be used to make decisions on optimum lateral placement.
Formation evaluation through casing is becoming more prevalent with the availability of multidetector pulsed-neutron tools (MDPNTs) from all major service companies. Monte Carlo modeling is important for not only optimizing nuclear tool designs but also for providing completion-specific petrophysical interpretations. Laboratory measurements provide key benchmarks for Monte Carlo modeling for validating liquid-saturated rock as well as gas-saturated rock models.
This paper presents a very-low-porosity gas saturation evaluation example for two limestone formations in Oklahoma. Data for saturation analysis were collected using a three-detector pulsed-neutron tool. The well was drilled through the following formations, beginning from the top depth: Union Valley limestone, Caney shale, Woodford shale, and Viola limestone. Union Valley limestone and Viola limestone are evaluated in this paper for gas saturation. Both formations have total porosity ranging from 1.5 to 2.5 pu. The total porosity used in the analysis is from the measurements obtained with nuclear magnetic resonance (NMR) tools.
When evaluating gas saturation in very-low porosity formations, the dynamic range of measurement can be limited for differences between raw measurements for 100% gas and 100% water. To provide a quantitative saturation analysis in low-porosity rock with total porosities less than 3 pu, a service provider adapted field-specific optimizations to the gas-saturation evaluation workflow. This modification accounts simultaneously for formation and borehole variations from the input properties to the computer model. During qualitative analysis of raw data, one limestone formation indicated low or no gas, while the second indicated possible accumulation of gas. When the modified saturation workflow was applied, during quantitative analysis, the gas volume was calculated for both formations. In summary, the benchmark for accurately modeling gas responses provided important validation for the new interpretation workflow of MDPNTs. The detailed petrophysical analysis provided reasonable saturation results for rocks of similar mineral composition. A consistent petrophysical workflow was applied through the interpretation. This paper also recommends best practices through collaboration with operators for detailed reservoir knowledge.
Quan, Tracy M. (Boone Pickens School of Geology, Oklahoma State University) | Puckette, James (Boone Pickens School of Geology, Oklahoma State University) | Rivera, Keith (Boone Pickens School of Geology, Oklahoma State University) | Otto, Brice (Boone Pickens School of Geology, Oklahoma State University) | Adigwe, Ekenemolise (Boone Pickens School of Geology, Oklahoma State University)
Assessment of unconventional hydrocarbon resources relies in part on characterizing the origin of the reservoir.
This includes determination of the original depositional conditions of the shale unit and any subsequent modifications to the organic matter present. Our research has found that sedimentary nitrogen isotope (d15N) measurements can be reliable proxies for determining water column redox state during deposition, as well as for compartmentalization and post-depositional fluid migration during catagenesis.
This paper summarizes our investigations into the use of d15N measurements as proxies to evaluate depositional redox conditions and fluid migration pathways, and suggests applications for these measurements in characterizing unconventional resource plays. Case studies were performed using d15N measurements from cores obtained from the Devonian-aged Woodford Shale and Caney Shale in Oklahoma, and Ohio Shale in Kentucky, and this data was combined with other geochemical and lithological measurements, including trace metals, thermal maturity, and gamma ray logs. Our data shows that bulk sedimentary d15N values primarily reflect water column redox conditions during deposition, as supported by correlation with redox-sensitive trace metals and other redox proxies.
Comparison of d15Nbulk values on a basin-wide scale indicates that interpretation of d15N as a redox proxy is consistent despite differences in the thermal maturity across the basin. Separation of d15Nbulk into inorganic and organic nitrogen isotope fractions appears to provide information about fluid migration pathways during catagenesis, as well as data regarding compartmentalization within an unconventional resource unit. As a result, measurement and interpretation of d15N values as part of a multi-proxy geochemical analysis can provide important details regarding the depositional and catagenic history of an unconventional resource play that may be essential to assessing the reservoir.
The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material. The Capillary Suction Time (CST) test has become a de facto standard test method, largely due to its simplicity and speed. The most obvious shortcoming of the CST test is that it introduces a medium (paper) that is far different from anything found in an actual reservoir; in fact, one may argue that the CST test is essentially a measure of the interaction of the test fluid with the paper. The lack of theoretical foundation of the CST test precludes reproduceable results or proper estimation of errors in measurement. We present a new test method that observes only intrinsic properties of the formation in contact with a test fluid, bolstered by a strong theoretical basis, in stark contrast to the CST test.
Our method preserves the desirable attributes of the CST test, but replaces imbibition into paper with imbibition into reservoir material. The method uses a comminuted sample, and the results from the imbibition step are used to determine formation wettability in the form of the advancing contact angle. The results from a subsequent drainage test are used to determine the receding contact angle, and the capillary pressure versus saturation curve.
Prior to performing the drainage test, test fluid is placed on top of the saturated pack and the permeability of the pack to the test fluid is determined. The permeability of the pack to liquid is then compared to the pretest permeability of the pack determined using nitrogen. Use of this pack as a testing environment allows the technique to be applied to formation samples of virtually any permeability and porosity.
We have found that there is no correlation between CST test data and the permeability data obtained using the new method presented here. We present several cases in which a positive result from a CST test is inconsistent with the results obtained from the new test method. We maintain that the discrepancies cast serious doubts on the general applicability of the CST test as a tool for studying rock/fluid interactions.
In summary, there is a great need to standardize testing that investigates rock/fluid interactions. The widely used CST method introduces a foreign material and it does not offer sufficient resolution, reproducibility, or estimation of error. Even if the CST method were adequate, the lack of standardization in testing and analysis methodologies makes comparisons of published results difficult.
Our method provides superior results. The strong theoretical foundation of the new method allows rigorous analysis making comparisons between treating fluid options far more trustworthy.
Brady, J. William (Devon Energy) | Shattuck, D. Phillip (Southwestern Energy) | Parker, M. Henry (Swift Energy) | Sramek, C. Shea (EV Downhole Video) | Jones, A. Michael (Occidental Petroleum) | Gould, J.H. (Baker Hughes) | Jayakumar, S. (Southwestern Energy)
Implementation of video production logging in conjunction with the use of high molecular weight polymer gels, has led to successful water isolation operations in the Fayetteville shale. The dry natural gas field, located in northern Arkansas, is a horizontal play with the wells cased, cemented, and completed with multi-stage slickwater fracture stimulations using perforation and plug technology (Harpel, 2012).
Accurate detection of extraneous water entry points along the wellbore is vital for precise water isolation treatment, while still protecting the hydrocarbon producing intervals. Conventional production logging tools have been utilized in the past but proved to be expensive, due to the wellbore configuration, and imprecise because of the horizontal trajectory and debris encountered in the wellbore, with the debris generally rendering the spinner tool inoperable. Video logging tools, deployed in combination with high frequency temperature and pressure gauges, have considerably improved identification of water entries along the wellbore. In addition, the use of a smaller logging assembly has also drastically reduced workover costs by permitting logging through the existing 2-3/8?? OD production tubing whereas conventional production logging required the removal of the production tubing due to size limitations. By maintaining this wellbore configuration the flowing conditions remain undisturbed and increase the accuracy of the production log.
Based on video production log results the proper water isolation operation is subsequently selected. While cement squeezes and mechanical isolation tools have been applied successfully in horizontal wells to isolate inflow from water producing perforations, they are limited in their applications due to the wellbore configuration and operational costs. Recently, treatment of water producing perforations with chrome (III) carboxylate acrylamide polymer (CC/AP) gel technology has allowed selective treatment in additional sections of the wellbore. These gel treatments have yielded strong results by isolating water production and increasing gas production by reducing the flowing bottomhole pressure. Evaluation and selection of the appropriate polymer gel is discussed along with design considerations and implementation.