ALBERT

Description: We measured the permeability of 30 samples extracted from 6 sets of compaction bands and the adjacent host rocks of the Jurassic aeolian Aztec Sandstone exposed in the Valley of Fire State Park in Nevada using core flooding experiments. The results show that the permeability within the high-angle compaction bands (three sets) is consistently three orders of magnitude lower than that of the host rocks. For the bed-parallel compaction bands, the measured permeability reduction is about half an order to three orders of magnitude for two sets of bands, and there is no detected permeability reduction for the samples from one set. For the samples that show permeability reduction within high-angle and bed-parallel compaction bands, the results are generally consistent with the data estimated from two-dimensional segmented image analyses in previous studies. Permeability of the samples used in the laboratory experiments was also obtained numerically based on three-dimensional tomographic images scanned from micro-samples and lattice-Boltzmann flow simulations. In addition, backscatter electron images (BEI) and energy dispersive spectroscopy images (EDSI) of thin sections were used to estimate the clay content inside and outside the bands. Large differences exist between the lab-based and image-based permeability and porosity measurements of compaction bands and host rocks. Possible factors causing these differences are different sample sizes and heterogeneities within the host rocks, calibration on the image segmentation, and incomplete characterization of clay minerals and fines migration during lab-based experiments. Given the wide range of permeability reductions within compaction bands of different orientations by different investigators, their impact on fluid flow should be evaluated case by case, one should consider their dimensions and distributions.

Description: Subsurface pressures strongly influence the migration and trapping of hydrocarbons and impact the safety and efficiency of drilling operations. The pore pressure field of the northern Gulf of Mexico (GOM) was analyzed at 1000-ft (305-m) depth intervals from 2500 to 17,500 ft (762 to 5334 m) below the sea floor. Two variables were mapped: 12,976 initial hydrocarbon reservoir pressure gradient values and 43,276 observations on drilling fluid (mud) weight. Because of the acute importance of assessing estimate uncertainty, ordinary kriging was employed, providing explicit evaluations of confidence surrounding mapped values. Expected values and confidence intervals for the distribution of both variables were estimated by $$9\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{mi}}^{2}$$ ( $$23.3\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{km}}^{2}$$ ) grid cells across the GOM for each of the 15 depth intervals. Estimation variances were also used to clip each map to specific extents, within which a uniform minimum threshold of certainty was exceeded. Characteristic of young basins with high sedimentation rates, mean pore pressure exceeded hydrostatic pressure throughout the GOM. Four provinces of internally consistent pressure regimes were defined: three south of Louisiana and one off the Texas coast. They reflect geologic controls on pressure arising from regional patterns of sedimentation and the resultant timing and geometry of salt tectonism. One GOM-wide (shallow) vertical transition in the pressure field was found in the mud weight data, and a second vertical transition (deep) occurred in both variables. Hot spot analysis was also applied to identify specific contiguous areas of abnormally high or low rates of change in pressure gradient and mud weight between depth-adjacent intervals.

Description: As one of the six subbasins in the lacustrine Bohai Bay basin, the Jizhong subbasin is characterized by a dominance of the petroleum reserves located in buried-hill traps of Paleozoic and Proterozoic marine carbonates, particularly the latter. This paper documents the revitalization of exploration of the buried-hill play and discusses other play fairways not previously considered through use of case studies. Discovery of the largest field, Renqiu field, in 1975 led to the establishment of the buried-hill play. In this play, oil derived from the Paleogene lacustrine source rocks charged into and accumulated in the underlying Proterozoic marine carbonate reservoirs. A number of buried-hill fields were discovered within a time span of ca. 10 yr in the subbasin. With more and more large buried-hill structures at depths of less than 5000 m (〈16,400 ft) being drilled, the annual reserve addition showed a rapid decline until 2006. The application of new technologies including reprocessing of merged three-dimensional seismic data, improved logging, and testing techniques, together with innovative exploration ideas, made it possible to revitalize the buried-hill play. The exploration success lies with the focus change from targeting the conventional shallow to moderately buried hills to the unconventional buried-hill pools, which include deeply buried hilltop, hillslope, and intrahill pools. Case studies of one conventional buried-hill field (Renqiu field) and three unconventional buried-hill fields (Chang-3, Wengu-3, and Niudong-1 fields), together with modern geological investigations, indicate that there still exists significant exploration potential for the buried-hill play in the Jizhong subbasin. The potential largely lies with the unconventional buried hills. The Baxian, Wuqing, and Baoding depressions are favorable fairways for the deeply buried hill pools, represented by the Niudong-1 field. The Wenan slope is the favorable fairway for the intrahill pools, represented by the Chang-3 and Wengu-3 fields.

Description: Total dissolved solids (TDS) concentrations of 258 Lower Cretaceous McMurray Formation water samples in the Athabasca oil sands region (54 to 58°N and 110 to 114°W) were mapped using published data from recent government reports and environmental impact assessments. McMurray Formation waters varied from nonsaline (240 mg/L) to brine (279,000 mg/L) with a regional trend of high salinity water approximately following the partial dissolution front of the Devonian Prairie Evaporite Formation. The simplest hydrogeological explanation for the observed formation water salinity data is that Devonian aquifers are locally connected to the McMurray Formation via conduits in the sub-Cretaceous karst system in the region overlying the partial dissolution front of the Prairie Evaporite Formation. The driving force for upward formation water flow is provided by the Pleistocene glaciation events that reversed the regional Devonian flow system over the past 2 m.y. in the Athabasca region. This study demonstrates that a detailed approach to hydrogeological assessment is required to elucidate TDS concentrations in McMurray Formation waters at an individual lease-area scale. The observed heterogeneity in formation water TDS and the potential for present day upward flow has implications for both mining and in situ oil sands resource development.

Description: This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI 〉5%, (2) high GR values (commonly 〉~90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.

Description: During the Alleghenian Orogeny, Upper Silurian–Pennsylvanian sediments were deformed by occasional gently dipping planar forethrusts and abundant, large, steeply dipping kink bands that extend down to the Silurian Syracuse Salt decollement. As the internal bedding dip within the kink bands is frequently steep, kink bands are poorly imaged in seismic reflection data. Therefore, they can have the appearance of steep reverse faults; however, geosteering data indicate that where these structures intersect the wellbore, they are folds, not faults. Kink bands occur on a range of scales, and their upward extent is controlled by a series of detachment levels, including at the organic-rich Marcellus and Geneseo Shales; a hierarchy of kink bands is therefore recognized. The detachment levels were sites of kink band reflection, resulting in upward converging pairs of kink bands that formed pop-down structures that protruded into the underlying salt. The dips of the thrusts and kink bands calculated from seismic interpretation fit well with theoretical models and published empirical descriptions: reverse structures dipping at less than 45° are thrusts, those with dip angles over 45° are kink bands. Areas of thick, primary salt are dominated by large anticlines, with their hinterlandward flanks defined by kink bands that extend to the present-day topographic surface. The structures may have initiated as sinusoidal folds, which became increasingly asymmetrical as they developed. The recognition of this style of deformation can improve the accuracy of horizontal well placement and has implications for reservoir permeability and integrity.

Description: Changes in elemental chemistry have been used to define stratigraphic correlations between wellbores in petroleum basins. Few publications, however, relate defined chemical stratigraphy to physical correlations, and none have been found that do so in fluvial systems. Here, chemostratigraphy is applied to Permian fluvial sediments within the Beaufort Group of the Karoo Basin in South Africa, and a correlation between three logged sections is defined. This correlation is tested against physically determined chronostratigraphic correlations achieved using Heli-LIDAR data to provide a high-resolution correlation between two sections 7 km (4.4 mi) apart, and mapping of strata using Google Earth to produce a correlation between sections 25.5 km (15.8 mi) apart. The chemostratigraphic characterization that is defined using data from fine-grained lithologies resulted in the recognition of eight chemostratigraphic packages, with thicknesses between 50 and 250 m (164 and 820 ft) over a stratigraphic interval of approximately 900 m (2953 ft). Two distinctive changes in geochemical composition of the coarser lithologies (fluvial channel belts) were seen over this interval. In the two sections that are 7 km (4.4 mi) apart, higher resolution subdivision of chemostratigraphic packages was achieved to produce four correlative geochemical units (30–60 m [98–197 ft] in thickness) that provide a high-resolution correlation. The chemostratigraphic and chronostratigraphic correlations are in close agreement in both the 7-km- (4.4-mi) and the 25.5-km- (15.8 mi) spaced sections. The thickness of the study interval and spacing of sections is analogous to published chemostratigraphy studies on subsurface sequences; thereby, ground truthing the use of chemostratigraphy for correlation in subsurface fluvial systems that are, to some degree, analogous to the Beaufort Group sediments of this paper.

Description: Between 2005 and 2014 in Pennsylvania, about 4000 Marcellus wells were drilled horizontally and hydraulically fractured for natural gas. During the flowback period after hydrofracturing, 2 to $$4\times {10}^{3}\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ (7 to $$14\times {10}^{4}\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{ft}}^{3}$$ ) of brine returned to the surface from each horizontal well. This Na-Ca-Cl brine also contains minor radioactive elements, organic compounds, and metals such as Ba and Sr, and cannot by law be discharged untreated into surface waters. The salts increase in concentration to $$\sim 270\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{kg}/{\mathrm{m}}^{3}$$ ( $$\sim 16.9\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{lb}/{\mathrm{ft}}^{3}$$ ) in later flowback. To develop economic methods of brine disposal, the provenance of brine salts must be understood. Flowback volume generally corresponds to ~10% to 20% of the injected water. Apparently, the remaining water imbibes into the shale. A mass balance calculation can explain all the salt in the flowback if 2% by volume of the shale initially contains water as capillary-bound or free Appalachian brine. In that case, only 0.1%–0.2% of the brine salt in the shale accessed by one well need be mobilized. Changing salt concentration in flowback can be explained using a model that describes diffusion of salt from brine into millimeter-wide hydrofractures spaced 1 per m (0.3 per ft) that are initially filled by dilute injection water. Although the production lifetimes of Marcellus wells remain unknown, the model predicts that brines will be produced and reach 80% of concentration of initial brines after ~1 yr. Better understanding of this diffusion could (1) provide better long-term planning for brine disposal; and (2) constrain how the hydrofractures interact with the low-permeability shale matrix.

Description: Assessing the production potential of shale gas can be assisted by constructing a simple, physics-based model for the productivity of individual wells. We adopt the simplest plausible physical model: one-dimensional pressure diffusion from a cuboid region with the effective area of hydrofractures as base and the length of horizontal well as height. We formulate a nonlinear initial boundary value problem for transient flow of real gas that may sorb on the rock and solve it numerically. In principle, solutions of this problem depend on several parameters, but in practice within a given gas field, all but two can be fixed at typical values, providing a nearly universal curve for which only the appropriate scales of time in production and cumulative production need to be determined for each well. The scaling curve has the property that production rate declines as one over the square root of time until the well starts to be pressure depleted, and later it declines exponentially. We show that this simple model provides a surprisingly accurate description of gas extraction from 8305 horizontal wells in the United States’ oldest shale play, the Barnett Shale. Good agreement exists with the scaling theory for 2133 horizontal wells in which production started to decline exponentially in less than 10 yr. We provide upper and lower bounds on the time in production and original gas in place. NOMENCLATURE Symbols and dimensions of key quantities Symbol SI dimensions Field dimensions $$c$$ –compressibility $${\mathrm{Pa}}^{-1}$$ μ cip $$d$$ –half-distance between hydrofractures m ft $$D$$ –production decline coefficient $$k$$ –permeability $${\mathrm{m}}^{2}$$ darcy $$K$$ –partitioning coefficient $$m$$ –gas pseudopressure $$\mathrm{Pa}\hbox{ \hspace{0.17em} }{\mathrm{s}}^{-1}$$ $${\mathrm{psi}}^{2}/\mathrm{cp}$$ $$\mathfrak{m}$$ –cumulative produced mass kg ton $$\mathcal{M}$$ –Original gas in place kg ton $$M$$ –molecular weight kmol lbmol $$H$$ –formation thickness m ft $$p$$ –pressure Pa psi $$q$$ –volumetric flow rate $${\mathrm{m}}^{3}\hbox{ \hspace{0.17em} }{\mathrm{s}}^{-1}$$ bbl/d $$Q$$ –volumetric cumulative production $${\mathrm{m}}^{3}$$ bbl $$R$$ —universal gas constant J/kmol-K psi- $${\mathrm{ft}}^{3}/\mathrm{lb}$$ -mol $$\mathrm{RF}$$ –recovery factor $$S$$ –saturation $$t$$ –time in production s month, y $$T$$ –temperature K °F, °C $$\widehat{v}$$ –specific volume $${\mathrm{m}}^{3}/\mathrm{kg}$$ $${\mathrm{ft}}^{3}/\mathrm{lbm}$$ $$\mathbf{\boldsymbol{y}}$$ –molar composition $$Z$$ –compressibility factor $$\alpha $$ –hydraulic diffusivity $${\mathrm{m}}^{2}\hbox{ \hspace{0.17em} }{\mathrm{s}}^{-1}$$ $${\mathrm{ft}}^{2}/\mathrm{y}$$ $$\kappa $$ –dimensionless constant for gas production in square root phase $$\mathcal{K}$$ –dimensional constant for gas production in square root phase $$\mathrm{kg}/\sqrt{\mathrm{s}}$$ $$\mathrm{ton}/\sqrt{\hbox{ month }}$$ $$\mu $$ –gas viscosity Pa s cp $$\rho $$ –density $$\mathrm{kg}\hbox{ \hspace{0.17em} }{\mathrm{m}}^{-3}$$ $$\mathrm{lbm}/{\mathrm{ft}}^{3}$$ $$\tau $$ –time to interference s y $$\phi $$ –porosity Subscripts and Superscripts Symbol Meaning $$a$$ adsorbed $$f$$ (hydro)fracture $$g$$ gas $$i$$ initial $$L$$ Langmuir $$ST$$ stock tank conditions $$w$$ water $$wc$$ connate water ~ dimensionless specific 0 reference or standard conditions

Description: Detailed stratigraphic and paleogeographic analyses of data from 72 boreholes for the Middle Jurassic intermontane fluvial-lacustrine coal-bearing sequences were conducted in the Yuqia coalfield of the northern Qaidam Basin, northwestern China. Three third-order sequences lasting in total ca. 10.6 m.y., and an internal lowstand systems tract (LST), transgressive systems tract (TST), highstand systems tract (HST), and falling-stage systems tract (FSST) have been identified. A series of sequence-specific paleogeographic maps have been constructed based on the contours of lithological parameters. The paleogeographic units include alluvial fan-braided (meandering) fluvial plain, upper delta plain, lower delta plain, subaqueous delta, shore-shallow lake, and deep lake. The preferred sites of coal accumulation are interdelta bays, upper delta plains, lower delta plains, and fluvial back swamps. The sequence stratigraphic and sedimentological analysis of the Middle Jurassic coal-bearing measures of the Yuqia coalfield provides a basis for a comprehensive coal accumulation model that involves a six-period evolution from the LST, early TST, late TST, early HST, late HST to FSST. The major coal seams were accumulated in the early and late TST of the sequences S1 and S2. These results are of practical significance for coal resources exploration and enhance geological effects of prospecting engineering in the northern Qaidam Basin.