Production from organic-rich shale petroleum systems is extremely challenging due to the complex rock and flow characteristics. An accurate characterization of shale reservoir rock properties would positively impact hydrocarbon exploration and production planning. We integrate large-scale geologic components with small-scale petrophysical rock properties to categorize distinct rock types in low porosity and low permeability shales. We then use this workflow to distinguish three rock types in the reservoir interval of the Niobrara shale in the Denver Basin of the United States: The Upper Chalks (A, B, and C Chalk), the Marls (A, B, and C Marl), and the Lower Chalks (D Chalk and Fort Hays Limestone). In our study area, we find that the Upper Chalk has better reservoir-rock quality, moderate source-rock potential, stiffer rocks, and a higher fraction of compliant micro- and nanopores. On the other hand, the Marls have moderate reservoir-rock quality, and a higher source rock potential. Both the Upper Chalks and the Marls should have major economic potentials. The Lower Chalk has higher porosity and a higher fraction of micro-and nanopores; however, it exhibits poor source rock potential. The measured core data indicates large mineralogy, organic-richness, and porosity heterogeneities throughout the Niobrara interval at all scale.
Unconventional petroleum systems are highly complex hydrocarbon resource plays both at the reservoir scale and at the pore scale (Aplin and Macquaker, 2011; Loucks et al., 2012; Hart et al., 2013; Hackley and Cardott, 2016). These organic-rich sedimentary plays, generally described as shale reservoirs, are composed of very fine silt-and clay-sized particles with grain sizes < 62.5 μm (Loucks et al., 2009; Nichols, 2009; Passey et al., 2010; Kuila et al., 2014; Saidian et al., 2014). They undergo extensive post-depositional diagenesis that transforms rock composition and texture, hydrocarbon storage and productivity, and reservoir flow features (Rushing et al., 2008; McCarthy et al., 2011; Jarvie, 2012; Milliken et al., 2012). Although some shale rock facies can retain depositional attributes during diagenesis, many critical reservoir properties, such as, mineralogy, pore structure, organic richness and present-day organic potential, etc., are significantly perturbed (Hackley and Cardott, 2016).
The genesis and relationship between the existence of bedding-parallel, calcite-filled fractures known as "beef fractures" and different organic-rich shale and geomechanical facies has been examined by interpreting the concentration of these fractures across various facies. The force of petroleum expulsion is complimented with the force of crystallization to explain a possible mechanism for generating "beef fractures." Bedding-parallel fracturing is always favored during petroleum expulsion in organic-rich shales. The mechanism of forming veins, in general, has long been debated. It has been whether vein crystals infill preexisting fractures or grow and propagate the vein by causing the fracturing. This study concludes with a suggested process for forming "beef fractures" in organic-rich shales as follows: 1. Force of petroleum expulsion creates sites of opportunities in the form of bedding-parallel fractures; 2. Thin film of supersaturated solution in-fills these sites of opportunities; 3. Mineral crystals utilize the site of opportunities and use them as sites for precipitation; 4. Crystal growth exerts pressure creating force of crystallization; 5. Depending on the aspect ratio of fracture, the force of crystallization extends the fracture forming the "beef" with prismatic calcite crystals growing perpendicular to the fracture walls. Observations and data analyses were made on six organic-rich shales: 1) Devonian/Mississippian Bakken, 2 and 3) Jurassic Haynesville and Vaca Muerta, 4 and 5) Late Cretaceous Niobrara and Eagle Ford, and 6) Eocene Green River (Mahogany Bench). The results provide explanations of the associations of bedding-parallel fracturing with organic-rich shale and geomechanical facies.
Resisitivity log is one of the most important tools to find oil and gas saturated intervals. In unconventional oil and gas producing rocks, however, this tool is affected by many factors and not considered very reliable. Shale reservoir rocks usually have high total specific surface area (TSSA) due to high clay and total organic content (TOC) and nano-scale pores. Resistivity values are rather low and usually not indicative of reservoir zones in high TSSA rocks. We measured the TSSA using nitrogen adsorption and cation exchange capacity (CEC) techniques. Clays and organic matter (OM) affect the measured TSSA using either technique. To more accurately calculate the water saturation using available models this effect must be taken into account. We investigate here the mineralogical associations of CEC and TSSA and their effects on resistivity in shale reservoirs.
We have studied samples from oil and gas producing reservoirs such as Bakken, Haynesville, European Silurian, Niobrara, and Monterey formations. We measured CEC using Co(III)-hexamine3+ with the spectrophotometric technique and calculated the equivalent TSSA (CEC-TSSA). We also measured the specific surface area using sub-critical Nitrogen gas adsorption technique (N2-SSA). Rock mineralogy, organic matter properties and scanning electron microscope (SEM) images were used to further analyze the data.
We find that CEC values are directly correlated with the clay type and content regardless of the OM content or level of thermal maturity. Smectite and illite (when negligible smectite is present) dominate the CEC value in shales. N2-SSA correlates with clay content, especially smectite and illite, but is less sensitive to clay type as CEC. This correlation between N2-SSA and clay content was observed in Bakken (no organic matter), thermally mature (gas window) Haynesville, and low TOC (<2.67 wt%) Niobrara (oil window) samples. We also find that OM significantly affects N2-SSA in two different ways: (1) Blockage of pores and throats by bituminous kerogen, which limits the accessibility of nitrogen to clay surfaces. This effect was observed in thermally immature (oil window) Niobrara (TOC>2.6 wt%) and Monterey shales. (2) Development of nano-scale OM-hosted pores with high surface area mostly for thermally mature (gas window) shales as observed in high TOC (> 1.5 wt %) Silurian shales. Correlation with N2-SSA and CEC values revealed that the average charge density for most of the shales in this study varies between 3-5 e/nm2 and for some high TOC Niobrara samples can be as high as 32. Relatively higher charge density is due to underestimation of the TSSA by nitrogen adsorption technique. Our results aid in understanding the low electrical resistivity response and in establishing correlations to calculate the CEC and specific surface area for resistivity models.
Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales.
The US shale gas story actually featured natural fractures. William Hart, a local gunsmith, drilled the first commercial natural shale gas well in US in Fredonia, Chautauqua County, NY in 1821, in shallow, low-pressure rock with fractures . The well was first dug to a depth of 27ft in a shale which outcropped in the area, then later drilled to a depth of 70ft using 1.5 inch diameter borehole. The produced gas was piped to an innkeeper on a stagecoach route. Then the well was produced without any stimulation for 37 years until 1858 when it supplied enough natural gas for a grist mill and for lighting in four shops. It was a combination of the idea from Mr. Hart to drill the well and the presence of the natural fractures in the gas shale that made the 1st commercial shale gas discovery possible in shale gas history.
Silo Field, located in the northern Denver Basin, is an important field for Niobrara oil production. The production is heavily controlled by the presence of open, vertical, natural fractures but the genesis of these features is not understood. A 3-D seismic survey, covering approximately 30 square miles in the heart of Silo Field was interpreted to determine the nature of the fractures. It also aided in the examination of the Permian salt edge and the Precambrian basement in the field. FMI logs and core descriptions provided additional information for the study. Based on the interpretations, the faults and fractures of the Niobrara have various causes including: underlying basement structure and dewatering during burial compaction. The Permian salt edge is oriented NW-SE across the survey area and an isochron from the Permian salt to the Wolfcamp (base salt) horizons illustrates the highly irregular nature of the salt edge. The irregularity of the salt edge suggests that salt dissolution created the edge rather than salt deposition. Where the salt is absent in Silo, a thickened Dakota-Sundance interval compensates for the lack of salt. This compensation creates a structural monocline in the strata overlying the salt edge due to differential compaction. Differential compaction is not the only cause for the monocline. Examining the basement horizon shows that there are possible basement faults that also contribute to the location of the structural monocline within Silo Field. It is also likely that basement faults control the location of the salt edge. Analyses of FMI logs within and outside of the main field area demonstrate that the orientation of natural fractures changes rapidly over short distances. In the southern part of the field, the dominant fracture orientation is NW-SE, similar to the underlying basement structure. Less than five miles south of the field, the fracture direction changes to a more N-S orientation. This has implications for future development of Silo Field and careful consideration is needed when attempting to develop outside the main field area.
Saidian, Milad (Colorado School of Mines) | Kuila, Utpalendu (Colorado School of Mines) | Rivera, Saul (Colorado School of Mines) | Godinez, Lemuel J. (Colorado School of Mines) | Prasad, Manika (Colorado School of Mines)
In mudrocks, these measurements are challenging due to the presence of fine grains, small pores, high clay content, swelling clay minerals, pores hosted in organic content, and possibly, mixed wettability. We used samples from the Monterey, Haynesville, Niobrara and Eastern European Silurian Formations. We measured porosity and pore/throat size distribution (PSD) of the samples using the subcritical nitrogen gas adsorption (N2) analysis at 77.3 K, the mercury intrusion (MI), and the low-field (2 MHz) nuclear magnetic resonance (NMR). Porosity was also measured with the water immersion (WI) and the helium porosimetry (GRI) techniques. The effect of texture and rock matrix components on porosity and pore-size distribution have been studied considering clay content and type, and total organic carbon (TOC).
Kuila, Utpalendu (Colorado School of Mines) | Prasad, Manika (Colorado School of Mines) | Derkowski, Arkadiusz (Institute of Geological Sciences, Polish Academy of Sciences) | McCarty, Douglas K. (Energy Technology Company, Chevron)
Speculation exists about the presence of micropore and mesopore networks either exclusively within the organic matter or as pore systems in the inorganic components. This study presents a comparison of pore-size distributions (PSD) in a set of fine grained rocks from the Niobrara Formation using a combination of meticulous, precise, and repeatable laboratory preparation and measurement techniques. The analyses were performed on aliquot samples of ground powders (<0.4 mm) following rigorous procedures of homogenization and division (splitting) to obtain mineralogically and chemically equivalent portions for each analysis. The mesopore and micropore distribution was measured by conventional subcritical N2 gas-adsorption analysis at 77.3 K. These results, combined with quantitative mineral analysis by XRD and organic content and maturity measurements, indicate that the abundance of illite-smectite group clay controls the small scale pore features in the Niobrara Formation. The samples show a characteristic 3 nm pore-size distribution peak that correlates strongly with clay abundance, but not with organic content. The low thermal maturity of the organic matter (OM) further implies the lack of associated small pores. Instead, this non-porous OM hinders access to the fine mesopore structure of the clay aggregates.
Since 1981, nearly 1,000 wells have been drilled in the Denver basin of northeastern Colorado with the Codell sandstone as their primary target. The majority of this exploration has been in the axial portion of the basin, in Townships 4 to 7 North. Ranges 64 to 68 West, in Weld and Larimer counties. Drilling depths of Codell wells range from 6,800 to 7,400 ft [2073 to 2256 m].
Recently discovered oil and gas production in the Codell sandstone encompasses several hundred square miles. Thickness and lithology of the formation are remarkably similar across this widespread area. Geologic limits of this reservoir are less distinct than in most sandstone exploration targets; therefore, geologic parameters must be considered over a large area.
Since 1981, nearly 1,000 wells have been drilled in the Denver basin of eastern Colorado with Codell sandstone as the primary target. The majority of this exploration has been in Townships 4 to 7 North, Ranges to 68 West, in Weld and Larimer counties (Fig. 1). Codell wells in this area range from 6,800 to 7,400 ft [2073 to 2256 m] in depth.
The Codell sandstone is the uppermost member of the Carlile formation, which is Upper Cretaceous (Turonian) in age. The Codell is immediately overlain by the Fort Hays limestone member of the Niobrara formation. Both the upper and lower contacts of the Codell are unconformable.
The productive sandstone is a widespread, blanket-type marine shelf sandstone of relatively uniform thickness and lithology across the area of current activity. The sand-stone is dark gray, very fine grained, and contains abundant clay, both authigenic and detrital. Density-log-measured porosity ranges from less than 8 to 22%, and core measurements have indicated permeability in the 0.01-to-0.1-md range. The productive area occupies a position that crosses the current axis of the Denver basin. position that crosses the current axis of the Denver basin. Fluid characteristics of the reservoir vary greatly across the area of Codell production. Bottomhole temperatures (BHT's) of 240 deg. F 11 16 deg. C] and bottomhole pressures (BHP's) in excess of 4,000 psi [28 MPa] are common in Codell wells, making the Codell an anomalous reservoir for the typically underpressured Denver basin.
Initial producing GOR's vary from less than 1.000 to more than 15,000 scf/bbl [180 to 2702 std m /m ] across the current productive area. Subtle variations in openhole log characteristics can be used to predict major differences in GOR.
The Codell sandstone in the study area is the uppermost member of the Carlile shale. It is Upper Cretaceous Turonian age and is overlain by the Fort Hays limestone member of the Niobrara formation. Both upper and lower contacts of the Codell are unconformable (Fig. 2). The Codell sandstone and the overlying disconformity represent the final stage in the regression of the Greenhorn Seaway, and a hiatus prior to the inundation of the area by the Niobrara Seaway.
Lithology and Mineralogy
Examination of two cores of Codell sandstone from the Bracewell field area (Sec. 22, TSN and R66W), as well as many drill cutting and outcrop samples, is the basis for the following lithologic description (Fig. 3).
The Codell sandstone in the study area is a fine- to very-fine-grained sandstone, medium to dark gray, with predominant quartz and feldspar in a light-colored clay predominant quartz and feldspar in a light-colored clay matrix. Framework grains are angular to subangular and well sorted. Mineralogic percentages have been determined on a number of samples by X-ray diffraction techniques. A typical composition is 85% quartz, 6% feldspar. 7% illite, 2% chlorite, and a trace of mixed-layer iilite/montmorillonite. * Lawman's I petrographic study reveals a detrital quartz fraction of 65 %. Additional silica defined by X-ray diffraction is determined to be authigenic quartz overgrowths and lithic chert fragments. A scanning electron microscope study shows that the cementing material in Codell sandstone is mostly clay with some calcite and quartz, The authigenic clays presented are illite, mixed-layer illite/smectite, chlorite. and smectite. Thinly interbedded black shales are present throughout the zone.