The objective of our research is to reconcile the differences, in both age and relative stratigraphic position, between the Woodbine and Eagle Ford Groups in the outcrop and subsurface of the East Texas Basin. In the outcrop belt, organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Eagle Ford Group, where they overlie, and are separated by a regional unconformity from Early Cenomanian, organic-poor, and clay-rich mudstones of the Woodbine Group (Pepper Shale). In southern portions of the East Texas Basin, however, these same organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Maness Shale, which in turn, is overlain by Late Cenomanian to Turonian-aged mudstones (Pepper Shale) and sandstones (Dexter Formation) mapped as the Woodbine Group. Our approach to reconcile the lithostratigraphic juxtaposition between the two regions was to use chemo-stratigraphic and petrophysical data collected from the outcrops, as well as an adjacent shallow research borehole, in order to define key sequence stratigraphic units/surfaces, and then correlate the key units/surfaces from the outcrop belt into the subsurface.
Our research indicates that the Woodbine Group, is an older unconformity-bounded depositional sequence which is Early Cenomanian, whereas the Eagle Ford Group, is an overlying (younger) unconformity-bounded depositional sequence, which is Middle Cenomanian to Late Turonian. The unconformities that bound these units can be mapped from the outcrop belt into the subsurface of the East Texas Basin, to define coeval depositional sequences. As defined in this study, marine mudstones of the Woodbine Group, are clay- & silica-rich, TOC-poor, and characterized by low resistivity on geophysical logs. In general, the Woodbine Group thins, as well as transitions to more mudstone-prone facies, from northeast to southwest within the basin. While beyond the scope of this study, the Woodbine Group contains numerous higher-frequency sequences, which are stacked in an overall progradational (highstand) sequence set. The depositional profile of the unconformity which forms the top of this progradational succession sets up the relict physiographic (depositional shelf/slope/basin) profile for the overlying Eagle Ford Group.
Within the Lower Eagle Ford Formation, two high-frequency sequences, defined as the Lower and Upper Members, were defined. Within the Upper Eagle Ford Formation, three high-frequency sequences, defined as the Lower, Middle, and Upper Members, were defined. The Lower and Upper Members of the Lower Eagle Ford Formation, as well as the Lower Member of the Upper Eagle Ford Formation range from Middle Cenomanian to Early Turonian. These three high-frequency sequences contain marine mudstones that are carbonate- & TOC-rich, as well as clay- and quartz-poor, and are characterized by high resistivity values on geophysical logs. Furthermore, they are interpreted as a transgressive sequence set, with sequences that sequentially onlap, from older to younger, the inherited relict physiographic (depositional shelf/slope/basin) profile of the underlying Woodbine Group. In stark contrast, mudstones within the Middle and Upper Members of the Upper Eagle Ford Formation, which are Middle to Late Turonian, are clay-rich, TOC-poor, and characterized by low resistivity on geophysical logs. These two sequences, which are interpreted as a highstand sequence set, are sandstone-prone, and contain petroleum reservoirs that previously were incorrectly included within the Woodbine Group. Based on these correlations, updated sequence-based paleogeographic maps can be constructed for the first time across the East Texas Basin. These maps can in turn be used to define a robust portfolio of conventional, as well as unconventional tight-rock and source-rock, plays and play fairways, which are now based on a modern sequence stratigraphic, versus the traditional archaic lithostratigraphic framework.
Tight reservoirs with low and ultralow permeability must be successfully stimulated to produce at economic oil or gas rates. For this reason, costs of drilling and completing wells are very high in tight reservoirs. In order to reduce these costs, operators have often tried to replicate the same or similar hydraulic fracturing designs that have been successfully used in previous wells in the same geological area. This strategy sometimes results in unexpected surprises and operational challenges leading to unsuccessful stimulations and poor production performance. The major reason behind these challenges is that tight reservoirs exhibit a localized behavior with changes in reservoir quality such as mineralogy, hydrocarbon content, and thickness across the same reservoir.
In order to study the localized behavior of tight reservoirs; three wells that penetrated the Eaglebine formation in Texas were evaluated. The Eaglebine formation contains both the Eagle Ford and the Woodbine reservoirs. The combined Eagle Ford and Woodbine (Eaglebine) reservoir can sometimes exceed 1,000 feet in thickness. These reservoirs are present at depths between 6,500 and 15,000 feet in East Texas. In some areas, the Eaglebine contains a large percentage of silica-rich sands interbedded in organic rich shale and carbonate layers.
This paper investigates the reasons as to why same hydraulic fracturing techniques should not be applied necessarily for every well in the same geological area. Furthermore, it demonstrates how we can exploit the localized reservoir behavior to plan for future wells despite limited data availability. Data from mud logs, well logs, and cores, including mineralogy and geomechanical data are integrated to build the localized reservoir characterization model that can be used to plan how each individual well should be hydraulically fractured. The model provides information such as location of organic-rich zones, brittle zones, and ductile zones in a geological area. Lastly, it recommends the type of fracture fluid that can yield a successful stimulation operation in ductile or brittle zones.
Four thousand (4000) feet of core in Forty-one (41) wells, six (6) Maximum Flooding Surfaces (MFS), nannofossils and foraminiferal abundance peaks and marker species, 800+ TOC/%CO3 values were used to evaluate and correlate the Eagle Ford South Texas, Eaglebine in East Texas and Tuscaloosa in Louisiana-Mississippi. Interpretation of high resolution biostratigraphy, and well-log sequence stratigraphic analysis identified six (6) third order Galloway type sequences and maximum flooding surfaces (MFS) in all project wells from Webb county in South Texas to Wilkinson County Mississippi were used to demonstrate the time correlation of rocks of Eagle Ford age of different facies from East to West. It is especially important to correlate to the Tuscaloosa TMS because it is an emerging play and a new oil reservoir in Mississippi and Louisiana.
In order to understand the complex relationship vertically and laterally of the Eagle Ford, Eaglebine and Tuscaloosa calcareous nannofossils and foraminiferal high resolution biostratigraphic analysis, TOC/%CO3 and Maximum Flooding Surface sequence stratigraphic analysis were completed on the project wells. The depth of the high value intervals of TOC per well is proposed as a minimum depth for placement of the landing point for lateral wells.
Genetic Sequences range from Cenomanian 3 (Ce3) (96.01Ma) Sequence Boundary at top of Buda, to the Turonian 4 (Tu4) (87.88Ma) MFS in lower Austin. The Maness in South and East Texas basin, and Tuscaloosa in South Louisiana and Mississippi is characterized by Ce3 (95.69Ma) MFS. The Cenomanian Eagle Ford South Texas, Pepper shale in lower Woodbine Group East Texas Basin and the TMS in lower Tuscaloosa, are characterized by Ce4 (94.75Ma) and Ce5 (93.13Ma) MFS followed by a major unconformity at the Cenomanian–Turonian Boundary. The Turonian Eagle Ford South Texas, Eagle Ford Group (Upper Eaglebine) East Texas Basin and upper Tuscaloosa South Louisiana and Mississippi are characterized by the Tu1 (91.41Ma) to Tu4 (88.77Ma) MFS.
Diagnostic fracture-injection/falloff tests are the primary test method for prefracture calibration of stimulation treatment designs in unconventional reservoirs. Diagnostic fracture-injection/falloff tests can provide insight into the geomechanical and reservoir properties of a formation using the interpretation of specialized diagnostic plots. Collecting quality injection falloff test data in underpressured reservoirs can be challenging because of the tendency for the wells to go on vacuum. This occurs when the wellbore fluid hydrostatic pressure exceeds the formation pressure. This is true whether the pressure is recorded at surface or bottom hole. A downhole shut-in tool can isolate the formation from the hydrostatic pressure created by fluid above the tool, which helps prevent the well from going on vacuum. However, this method can add to testing costs, increase operational complexity, and increase the potential for test failures.
This paper presents a new method for test design and analysis of diagnostic fracture-injection/falloff tests conducted in underpressured reservoirs. A case study demonstrates a new workflow that combines a hybrid nitrogen fracture-injection/falloff test (NFIT) design using nitrogen as a displacement fluid and a new well-testing type-curve analysis methodology. This specialized workflow helps enable the creation of successful stimulation designs in wells that would otherwise be costly and operationally challenging to test and stimulate effectively.
Diagnostic fracture-injection/falloff tests are the primary method for prefracture calibration of stimulation treatments in unconventional reservoirs. These tests include injecting a small volume of fluid into the formation at a pressure that exceeds the fracture propagation pressure. This is followed by a shut-in period that allows pressure falloff. The injection/falloff sequence is recorded with high-resolution pressure transducers. Then, the data are analyzed to determine geomechanical and reservoir properties for fracture design and reservoir characterization.
The diagnostic fracture-injection/falloff tests analysis workflow uses multiple diagnostic plots, which provide a consistent method of observed data interpretation. The workflow comprises fracture property analysis, flow regime identification, straight-line before- and after-closure analysis, and a relatively new well-testing type-curve analysis. Classical G-function derivative analysis and log-log diagnostics as described by Barree et al. (2007) provide the methods for before-closure fracture property analysis and flow regime identification. Straight-line before- and after-closure analysis uses specialized Cartesian plots of the pressure falloff data with straight lines fitted to the observed data corresponding to the correct flow regimes. Conceptually, the diagnostics and analysis methodology are straightforward. However, observed falloff diagnostics in unconventional reservoirs are often misinterpreted, which can lead to erroneous fracturing parameters, reservoir pressure, and permeability estimates (Barree et al. 2007).
Albrecht, Tony (Geoscience, Hawkwood Energy, Denver, CO, United States) | Kerchner, Stacy (Engineering, Hawkwood Energy, Denver, CO, United States) | Brooks, Scott (Petrophysics, Hawkwood Energy, Denver, CO, United States) | Kolstad, Eric (Drilling, Hawkwood Energy, Denver, CO, United States) | Willms, Trevor (Engineering, Hawkwood Energy, Denver, CO, United States) | Klein, John (Geoscience, Hawkwood Energy, Denver, CO, United States) | Stemler, David (Geoscience, Hawkwood Energy, Denver, CO, United States)
The Mesozoic-aged Brazos Basin, situated at the southwestern-most extent of the East Texas Basin and along trend with the Maverick Basin, is bracketed by the Edwards Reef, San Marcos Arch and the Angelina Caldwell Flexure (
Donovan, A. D. (BP Exploration: Unconventionals) | Pope, M. C. (Texas A&M Department of Geology & Geophysics) | Gardner, R.M. (BP Reservoir Management) | Wehner, M.P. (Texas A&M Department of Geology & Geophysics) | Staerker, T.S. (BP Exploration: Unconventionals)
Often one of the most basic challenges of using outcrops to better understand the subsurface is simply terminology. These terminology challenges include: 1) provincial outcrop nomenclature; 2) the fundamentally different way stratigraphic units are commonly defined in the subsurface (by surfaces) versus outcrops (by lithology); and 3) local variations in member boundaries and/or member nomenclature used by different researchers.
In the subsurface of South Texas, the Eagle Ford Group is commonly divided into an organic-rich Lower Eagle Formation and a carbonate-rich Upper Eagle Ford Formation. In contrast, the coeval strata that crop out nearby in West Texas are traditionally referred to as the Boquillas Formation. Adding further complexity to the nomenclature issue is that previous workers defined anywhere from two to five informal members to the Boquillas Formation in West Texas, but the names, as well as the stratigraphic intervals defined by these members, all differ. In order to highlight the distinct lithologic units defined by previous worker, but also provide a clear and easy to use nomenclature that conveys superposition, a simple five-fold succession of informal lithostratigraphic units, termed A to E from the base up was proposed. Unit A consists of foram grainstone interbedded with dark gray mudstone, whereas unit B is dominated by organic-rich mudstone. Unit C consists of white foram packstone interbedded with gray mudstone, while unit D is dominated by yellow-ochre colored bioturbated skeletal wackestone/packstone. Unit E consists of thin-bedded skeletal grainstone interbedded with mudstone and bentonite beds.
Clearly, the first step in effectively using Boquillas outcrops of West Texas for comparison to the Eagle Ford in the subsurface of South Texas, is to refer to these strata as the Eagle Ford Group, as is done elsewhere in the state. By incorporating information from a handheld gamma ray spectrometer, as well as geochemical data, to the outcrop lithologic information, the Lower and Upper Eagle Ford formations as defined in South Texas can also be defined in the outcrops of West Texas. The Lower Eagle Ford Formation contains units A&B, while the Upper Eagle Ford Formation contains units C, D, and E. Similar to the subsurface of south Texas, the base of the Upper Eagle Ford Formation in the outcrops of West Texas is marked by a drop in total GR values driven by a drop in U-content, a drop in TOC content, and the onset of a positive d13C excursion. With the inclusion of geochemical and geophysical log data from a research borehole, a clay-rich high-density and low resistivity marker zone also is defined at the base of the Upper Eagle Ford Formation in the West Texas outcrops, similar to the base of the Upper Eagle Ford Formation in the subsurface of South Texas.
Using the geochemical, petro-physical, and lithologic information in the West Texas outcrops and research borehole four distinct allo-stratigraphic members (depositional sequences) more suitable for regional subsurface correlations can also be defined. The Lower (Lozier Canyon) Member of the Lower Eagle Ford Formation can be characterized as organic-rich (high resistivity) mudstone. In outcrop, it consists of unit A and the lower portions of unit B. The Upper (Antonio Creek) Member of the Lower Eagle Ford Formation can be characterized as uranium- and bentonite-rich (high GR) mudstone, with lower (1-2%) TOC content. In outcrop, this member consists of the upper portions of unit B. The Lower (Scott Ranch) Member of the Upper Eagle Ford Formation is a uranium-poor (low GR) interval consisting of interbedded limestone and mudstone. A diagnostic feature of this member, which includes unit C in outcrop, is the presence of a distinct positive d13C excursion at its base, the peak of which is taken as the geochemical proxy for the base of Turonian. The Upper (Langtry) Member of the Upper Eagle Ford Formation is bentonite-rich bioturbated mudstone with high GR and low resistivity values at its interpreted maximum flooding surface (mfs). In outcrop this member consists of units D and E. All four members can in turn be readily correlated into the subsurface of South Texas. With this stratigraphic framework in place, researchers can now use the West Texas Eagle Ford Group outcrops to more readily study specific portions of the Eagle Ford Group in the subsurface of South Texas, and use this information to better understand the facies, distributions, thickness variations, and reservoir properties of specific reservoir zones.
Brooks, Scott (Hawkwood Energy LLC, Denver, CO) | Willms, Trevor (Hawkwood Energy LLC, Denver, CO) | Albrecht, Tony (Hawkwood Energy LLC, Denver, CO) | Reischman, Richard (Edgar Ignacio Velez Arteaga) | Walsh, John (Schlumberger, Houston, TX) | Bammi, Sachin (Schlumberger, Houston, TX)
Intrinsic anisotropy is known to exist in most organic shales due to their layered nature. Horizontal and vertical mechanical properties can sometimes be drastically different. Taking these differences into account can result in higher than expected pre-job calculated frac gradients. Often this type of information is based solely on experience gained from hydraulically fracturing other wells in a given area. Logging data obtained prior to stimulation can help predict these higher fracture gradients and can provide great value in the design of an optimized stimulation. This study documents the integration of log data obtained in a vertical pilot well and its associated lateral wellbore in the lower Eagle Ford formation in Robertson county, Texas. Acoustic data obtained from a dipole sonic that was run in the vertical pilot were correlated with data acquired from a new slim dipole array sonic tool that was conveyed through the drillstring in a lateral well and into open hole after it was drilled. Slowness measurements taken from the vertical and horizontal well data sets suggest that a high amount of intrinsic anisotropy was present. These predictions were confirmed by the post job stimulation data from the horizontal well. Combining the stress and petrophysical interpretations based on other log measurements provided reservoir and stimulation quality indicators that were then compared to actual production. Lessons learned were then implemented in later wells resulting in improved stimulation efficiency and production.
As expansion into unconventional reservoirs continues, one of the key drivers of well performance has become completion efficiency. Much of this efficiency centers around finding the completion strategy that effectively drains the entire lateral in a horizontal wellbore. Different fracture spacing and perforation schemes have been attempted to try and accomplish maximum coverage with minimal interference between stages. However, even as fractures are planned with a particular spacing, there is no guarantee that every perforated interval will lead to a productive fracture. One of the key questions has been: How many of the fractures are actually contributing to production? Numerous authors have developed methods for estimating this number, and a small set of diagnostics tools are currently being used in the industry to evaluate fracture placement.
The Eagle Ford East-Eaglebine play is an emerging resource play located in East Texas. By definition, the Eaglebine play is given to the various formations deposited between the Lower Cretaceous Buda formation (base) and the prolific Upper Cretaceous Austin Chalk (top). From the outcrop, the Eagle Ford East-Eaglebine is a combination of the Eagle Ford and the Woodbine Groups and contains local formations such as the Eagle Ford Shale, Lewisville, Woodbine, Dexter, Sub-Clarksville, Pepper, and Maness shale. Most of these formations have produced oil and gas conventionally for decades and with horizontal drilling and multi-stage stimulations, operators are “redeveloping” these conventional plays and adding more focus on the unconventional nature of the hydrocarbon rich shale sections.
Acquisitions & Divestitures ("A&D") professionals routinely adjust the valuation parameters, on the basis of asset type being evaluated, to determine an acquisition price that is conservative yet competitive for use in a bid. A study of over seventy three A&D transactions over a two year period enabled us (the author’s team) to compare the valuation parameters for unconventional asset acquisitions vis-à-vis those for conventional asset acquisitions. Transaction data indicates that valuation metrics, particularly on a production multiple basis, for the acquisition of unconventional assets are significantly higher vis-à-vis those for the acquisition of conventional assets. The use of higher valuation multiples implies that the A&D market expects an unconventional asset to have lower risks and/or better growth prospects in relation to a conventional asset.
SPEE Monograph 3makesit clear that an unconventional asset – a term often used in A&D markets to describe a continuous hydrocarbon reservoir of low permeability which exists over a large geographic area and requires extensive stimulation to produce at commercial rates – does not always have fewer risks and/or more growth prospects. Therefore, the acquisition of an unconventional asset at overly aggressive valuation could potentially lead to underperformance and adverse financial consequences for the buyer. The high valuation multiple for Halcón Resources Corporation’s ("Halcón") acquisition of its Woodbine unconventional play in Texas, which so far has not met expectations, provides a glaring, well-documented example of underperformance with adverse financial consequences in recent history.
We believe buyers should use high valuation multiples with confidence only for those unconventional asset transactions which involve"resource play reservoirs" as defined in SPEE Monograph 3.
The paper concludes with our recommendations for due diligence and deal structuring with respect to an unconventional asset acquisition. We identify due diligence items which include the determination of whether or not an unconventional asset exhibits the technical characteristics of a resource play reservoir. Unfortunately, such determination requires extensive well data. Early in the exploration process, it may not be possible to determine if an unconventional asset has the technical characteristics of a resource play reservoir due to the lack of adequate well count and data. For such early stage unconventional asset acquisitions, we discuss certain deal structuring techniques which could potentially make bids more competitive and less risky.