Zafar is a strategy consultant with Accenture and is based out of Mumbai. Before Accenture, he worked for 5 years at Halliburton designing drill bits for oil and gas companies in South Asia. He has been a volunteer with TWA since 2013 supporting multiple sections prior to transitioning to a leadership role in 2018. He is a keen technophile, an avid debater, and a passionate Toastmaster. He has participated in and won several public speaking and debate competitions. His hobbies include running, collecting key-rings, building robots, and keeping abreast of global geopolitics. Kristin Cook is the Advisor to TWA. She is an MS candidate in Energy and Earth Resources at the University of Texas at Austin. Her interests include energy policy, oil and gas project development, and energy security and geopolitics. Prior to starting graduate school, Cook worked for 5 years as a production engineer in the San Juan Basin, a natural gas field in northwestern New Mexico.
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.
Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Goldstein, Robert (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
Huff-n-puff gas injection has proven to be effective for recovering more liquid hydrocarbons from hydraulically fractured and horizontally drilled wells in ultra-tight unconventional shales. The complexity of shales, however, inherent in the variation of mineral microstructure and heterogeneous pore space, makes accurate simulation of the huff-n-puff process for optimum recovery challenging. Therefore, this study deals with the visualization and quantification of the microstructure of Lower Eagle Ford (LEF) shale samples before and after hydrocarbon gas huff-n-puff recovery. This is used to produce reliable estimations of petrophysical (porosity, permeability) and intrinsic rock properties (tortuosity). The petrophysical and intrinsic property estimations measured provide accurate inputs for reservoir simulation for the huff-n-puff process.
The integrated workflow for pore-scale characterization includes scanning electron microscopy/backscattered electron microscopy (SEM/BSE), energy-dispersive X-ray spectroscopy (EDS), and focused ion beam-scanning electron microscopy (FIB-SEM). It includes mineral and maceral identification through elemental analysis, pore size and pore throat distribution, in addition to pore network development. A high pressure, high temperature (HPHT) system is used to expose the samples to hydrocarbon gas for 3 days before repeating the SEM measurements.
The 2-D SEM/BSE images are particularly useful at the micrometer scale, and show sediment particles, wispy seams of kerogen, discrete particles of depositional kerogen, and migrated organic matter embedded in a fine-grained matrix of clays, quartz, coccoliths, foraminifera, organic matter, and unidentifiable particles. Together, the SEM/BSE and FIB-SEM images show nano-scale pores in organic matter, as well as micro-scale intraparticle, interparticle, intercrystalline, breccia and fracture pores of varying sizes and geometries. Much of the pore space is impregnated with variously arranged porous organic matter which comes in later in the paragenesis. FIB-SEM images were utilized in the generation of pore network models. The EDS combined with SEM/BSE reveals spatially distributed diagenetic textures indicating calcite precipitation before pyrite, kaolinite precipitation, compactional fracturing and late migration of organic matter into open pore space. Significant findings include the differentiation of depositional kerogen from migrated organic matter (bitumen or solid bitumen/pyrobitumen). Most porosity is in the migrated organic matter, which has spongy or bubble pores, rather than in depositional kerogen. The pore-scale tortuosity in organic pores averages 1.56, 1.94, and 1.73 for the Lower Eagle Ford (LEF) samples A, B, and C, respectively. The tortuosity of the inorganic pore network is estimated at 1.60. Furthermore, the equivalent pore diameters from pore network models of both the organic and inorganic pores range from 13 nm – 580 nm and 20 nm – 4 μm, respectively. This is important because organic pores developed in both migrated solid bitumen (most common) and depositional kerogen (less common). These organic pore networks create permeability and provide diffusion pathways for gas molecules during the huff-n-puff process. After the hydrocarbon gas injection experiments, the gas exposure was observed to have displaced some of the migrated organic matter. In-situ interaction of injected hydrocarbon gas with bitumen/solid bitumen enhances our understanding of the recovery process.
Wellbores drilled on US land today are geosteered predominantly using total gamma ray measurements and periodic survey data. This approach results in a number of ambiguous scenarios whereby not enough data are available to make the correct interpretation decisions. It is for this reason that many horizontal wells are unknowingly in different locations from where they are reported to be both positionally and stratigraphically. Geosteering techniques employing high-quality azimuthal gamma imaging and continuous inclination measurements address some of the main challenges plaguing accurate wellbore placement in the Wolfcamp A and Wolfcamp B of the Southern Midland Basin. Azimuthal gamma image examples of stratified and non-stratified bedding are related to lithofacies observed in core, bringing visibility to internal geometries and demonstrating how depositional environment influences tool response from a gamma radiation standpoint. Azimuthal gamma logged in conjunction with an accurate continuous inclination measurement to reduce TVD error enhances the benefits to geosteering interpretation and bed dip calculation, resulting in higher confidence wellbore placement. Furthermore, azimuthal gamma and continuous inclination MWD tool designs are discussed in the context of the critical elements needed for accurate and high resolution measurements.
During development of the Eagle Ford unconventional resource near the San Marcos Arch, a non-productive mudstone associated with drilling issues was identified between the primary Eagle Ford producing zone and the underlying Buda Limestone. As the top of the Buda typically exhibits evidence of karsting but is unaltered when overlain by this mudstone, and the mudstone contains higher abundances of clay than the Eagle Ford, two questions were posed: (1) Does this mudstone represent a depositional system separate from the Eagle Ford and (2) does it act as a fracture barrier between the Eagle Ford and underlying water-bearing rocks?
The current study analyzed two cores from Lavaca and Fayette counties, which included petrographic, XRD, and geomechanical (point-load penetrometer and micro-rebound hammer) analyses to determine the mineralogy and geomechanical properties of the mudstone, the Eagle Ford, and the Buda. Logs from 345 wells within a six-county were used to correlate and map four horizons associated with the mudstone. These results were integrated with an earlier core study that included biostratigraphic, petrographic, XRD, and XRF analyses, and regional log correlations across the arch into the Brazos Basin.
The geomechanical tests found that the mudstone is significantly weaker than the overlying Eagle Ford, averaging 32% lower calculated unconfined compressive strength (UCS) values derived from the penetrometer and 36% lower using the micro-rebound hammer. Higher clay and lower calcite abundances within the mudstone are responsible for its lower strength; the XRD analyses found that the shale samples from the mudstone contained an average of 47% clay, whereas the Eagle Ford marls contained an average of 34% clay. The petrographic analyses found that the clay is concentrated in structureless layers that are interpreted to represent fluid-mud deposits associated with hypopycnal plumes.
The biostratigraphic study identified Early Cenomanian markers associated with the Maness Shale of East Texas which lies between the Woodbine and Buda, in agreement with the regional cross-sections which correlated the mudstone to the Maness. A hot gamma ray spike produced by a phosphatic lag at the top of the mudstone was key to the correlations. Thickness trends of the Maness differ considerably from the Eagle Ford; it has a distinct northeast-southwest trend and pinches out in southern Karnes County, suggesting that it was a depositional system unrelated to the Eagle Ford.
Comparison of Maness thicknesses with cumulative first year oil and water production data from over 2000 horizontal wells in the study area found a significant correlation between Maness thickness and water/oil ratios. In particular, there is a 50% decrease in water/oil ratios between Maness thicknesses of 5 to 10 ft, (1.5-3 m) suggesting that the Maness may be acting as a fracture barrier where it is >10 ft (3 m) thick.
Oilfield water management has become an increasingly critical aspect of oil and gas operations in the United States. With the generational changes in completion techniques making the frac jobs bigger and more resource intensive, proper water management and utilization is key in optimizing operations. At a high level, drought, municipal non-potable sources, produced water volumes, seismicity, SWD capacity, larger frac jobs, capital expense amongst others have drastically increased the considerations for efficient water management. With about 30% of the active North American fleets in the Permian, the issue has become particularly acute regionally. This is driven by the increasing requirements of hydraulic fracturing as an average US well in 2017 used around 9.8 million gallons of water for a frac job. In addition, produced and flowback water from oil and gas wells is an increasing liability for operators in active fields which can create treatment and logistics challenges.
The present paper combines data from a wide variety of sources and looks at the dynamic of produced water, frac water and disposed/injected water for operations. It provides a solid mass balance assessment of the water going in and out of the oil field. The paper also overlays several of the known trends to identify opportunities for efficiency gains as well as potential “cost crisis”. This allows for a more robust understanding of economic impact of the water management. Identifying these opportunities, the paper examines formation water chemistry trends and combines them with best practices to provide best practices for water treatment to impact operational efficiencies now as well as projects it in the future.
Overall, there is a clear increase in volume of produced water in these major oil producing regions, with the Delaware Basin alone increasing significantly (~80% increment in produced water since 2015) year on year since the emergence of horizontal drilling. The analysis also showed the impact on parallel industries like water midstream infrastructure and logistics development. Cost optimization has driven companies to take on more comprehensive projects with 50% or higher reductions in cost switching from trucking to pipeline.
This study analyzes the production data from 2,755 horizontal wells in the Haynesville shale. Correlations were generated to predict 4,5,6, and 7-year cumulative productions from initial 6,12 and 24-months production data. These correlations can help in field development planning and economic analysis. The residuals (Predicted – Actual Cumulative Production) from these correlations were also analyzed and this technique can be used to identify wells affected by interference, refracturing, frac-hits, etc.
The cumulative production estimates from the developed correlations were also compared with the corresponding estimates from the DCA equations (seven different DCA methods used). The accuracy of prediction based on correlations developed in this study is at par with the various standard DCA methods published and used in the industry. The correlations are much faster to use and easier to implement for a large number of wells.
Another objective of the paper was to develop P10, P50 and P90 type curves for the Haynesville shale using the available production data. A subset of the total wells i.e. 150 wells evenly distributed throughout the study area, were used for predicting type curves. These type curves were generated and compared using different Decline Curve Analysis (DCA) models. The different DCA methods predicted an uncertainty of 5 to 27 % for the P10, P50 and P90 production profiles.
Ely, John W. (Ely & Associates Corp) | Harper, Jon (Ely & Associates Corp) | Nieto, Esteban N. (Ely & Associates Corp) | Kousparis, Dimitrios (Paris Oil and Gas Corporation) | Kousparis, Andrew (Paris Oil and Gas Corporation) | Crumrine, Curt (W.B. Osborne Oil and Gas Corporation)
The Northern extension of the "COMBO" Barnett Shale is located primarily in Montague, Cooke, and Clay counties in the North Texas region. This play is unique in that the shale in the area is very rich in total organic content (TOC) and contains a relatively high concentration of carbonates throughout. This extension is primarily inside the the oil window of the Barnett, rather than predominately within the more gas-rich region, which dominates the rest of the shale's development throughout North Texas (See
One of the Wolfcamp's most active operators, the Houston independent has more than 3 billion BOE in estimated recoverable resources in the play. US proved reserves of crude oil and natural gas reached all-time highs at yearend 2017, as higher commodity prices encouraged more drilling and expanded the scope of what operators deem economically recoverable. Accounting for lease condensate, proved reserves were just under 42 billion bbl, up 19% year-over-year. Proved gas reserves were 464.3 Tcf, a 36.1% spike from a year earlier and well-above the 2014 all-time mark. Owing to the unconventional boom built on horizontal drilling and hydraulic fracturing, both oil and gas totals are twice their levels compared with a decade ago.
Due to the existence of hydration, underground complex accidents often occur in shale formation. Different from hydration swelling shale, the researches related to mechanical characteristics in carbonaceous shale that is symbiotic with coal-bed strata are less. The shale is rich in carbonized organic matter, often includes fossils like graptolite, and develops plentiful bedding planes. In order to study the influence of hydration on mechanical characteristics of carbonaceous shale, we have carried out some experiments, including mineral components, specific surface area, wettability, cationic exchange capacity, scanning electron microscope(SEM), triaxial compression experiment and shear strength experiment. The results show: (1) Carbonaceous shale is mainly composed of quartz and clay mineral and the main clay minerals are illite and illite-smectite mixed layer. (2) Carbonaceous shale is water wetness and oil wetness. As specific surface area, pore volume and the average diameter of pore are small, the capillary pressure of shale will be very high. (3) Carbonaceous shale has a mass of micro-cracks, micro-pores and bedding planes by scanning electron microscopy (SEM). The drilling fluid is easy to enter into the interior of the rock under the action of the pressure of the fluid column, the chemical potential difference and the capillary pressure, which result into the reduction of the strength parameters in the shale. Therefore, in the drilling process, the hydration function should not be ignored, which requires the strong sealing ability of the drilling fluid and the contact with the carbonaceous shale should be avoided as much as possible.
Malek Elgmati, Robert G, Younane A, Gareth R Chalmers investigated mineral composition and the content of clay minerals of typical hard brittle shale formation in Fort Worth basin, Appalachian basin, Anadarko basin and East Texas basin of North America by X ray diffraction method. Statistics results showed that the clay minerals content distribution in hard brittle shale formation was between 15% ~ 50%, the main clay minerals content is illite and clay minerals content of North America stratum is generally excluding illite-smectite mixed-layer and the content of illite in North America accounts for more than 75% of the total amount of clay minerals. Martin E Chenevert measured hydration swelling pressure when he was studying shale hydration, and the expansion pressure are expressed as the function of waters activity in the inside of shale, found water absorbing capacity increased with time in the process of shale hydration, the rock strength decreased with the increase of water absorbing capacity, and the one dimensional water absorption equation is given. Skipper, Chang FRC, Karaborni N T S, Emiel J and Smith based on computer molecular simulation concluded that the hydration process began when balance ion migrated on the surface of clay minerals, produced complete hydration process until the balance ion penetrated to intermediate sandwich of clay minerals and charge location had a great influence on the hydration process. H.C.H.Darley proposed that water would not disperse the hard brittle shale, but would enter the inner rock through tiny cracks in the hard brittle shale, causing the splitting and peeling of the rock. Yew C. H simulated the flow forms of water molecules within the shale hydration process by using thermal diffusion model, the influence of the water quantity of wall rock mechanics properties was concluded, and the wall stress distribution and stress was sensitive to shale water quantity. F.K.Mody found that the shale hydration changed the pore pressure and the effective stress state of the formation, and established a model of well wall stability based on chemical potential. Microstructure of hard brittle shale as a extremely important rock physical properties has been widely attention. Since Teraghi puts forward the concept of microstructure, the scholars have put forward various models such as the non-flocculated structure, flocculation structure, spatial dispersion structure to describe the microstructure of clay minerals.