BLTN04131 Organic geochemistry of oil and source rock strata of the Ordos Basin, north-central China
Paleozoic and Mesozoic strata and a suite of oil samples from wells in the Ordos Basin were studied to determine which strata are source
rocks for oil produced in the basin. Analyses included total organic carbon, Rock-Eval pyrolysis, vitrinite reflectance, and conventional biomarker analyses on source rock extracts.
Results reveal that Carboniferous coal and organic-rich fluvialdeltaic mudstone samples appear to be gas prone and mature to overmature. Both Upper Triassic and Middle Jurassic lacustrine mudstone samples contain organicmatter of sufficient quantity and good quality to be slightly immature or to have low thermal maturity.
Oil-oil correlations result in the establishment of one genetic family that can be divided into subfamilies based on degree of oxicity in the source environment, differences in thermal maturity, and differences in clay versus carbonate content of the source rock.
An oil-source rock correlation is established between produced oil and Upper Triassic source rock strata. Vitrinite data indicate that the source rock ismore thermallymature in the western part of the basin than in the east. These results should drive future exploration strategies for the basin. A bitumen vein is classified as pre-oil solid bitumen using biomarker data. Age-related biomarkers suggest it is derived from a pre-Jurassic source rock. Similar veins in other basins globally are linked to very rich source rocks.
BLTN06051 Methodology for risking fault seal capacity: Implications of fault zone architecture
We introduce a methodology for quantifying the risk associated with a seal for fault-bounded prospects. Applying this methodology, the aspects of fault seal are confined within four main risk categories. The methodology allows comparable criteria to be applied in the risking procedure to reduce uncertainty in fault seal assessments. As a foundation for the methodology, we combine onshore and offshore data from large faults and demonstrate how architecture and the distribution of fault rocks may influence sealing capacity. Despite the variable and complex structure of fault zones, we have observed fault zone characteristics that appear in common to the faults investigated, and we consider these factors to be crucial in the risking of fault seal predictions. The fault zones in our database, typically bounded by external slip surfaces, represent two main categories: (1) a layer of shale smear entrained into the fault zone and derived from a thick shale source layer within the sequence
offset by the fault and (2) fault zones characterized by internal slip surfaces, slivers of footwall and hanging-wall–derived material rotated
along the fault zone and commonly enclosed in a matrix of shaly-silty fault gouge. This study highlights the disparity between the complexity of actual faults and the abrasion-type shale gouge ratio (SGR) algorithm currently used in the industry to estimate sealing capacity of faults, which assumes that the seismically derived throw is concentrated in a single fault plane. We discuss how this may influence sequence juxtaposition across a fault, the associated SGR values, and ultimately, the fault seal risking.
BLTN06052 Reservoir quality, textural evolution, and origin of fault-associated dolomites
Fault-associated dolomitized carbonates are proven hydrocarbon reservoirs in the subsurface; yet their origins and spatial variability in reservoir quality are poorly understood. Fault-associated dolomitization has affected a 4–8-km (2.5–5-mi)-wide strip of innerplatform carbonates of theOligocene–Miocene Taballar Limestone, exposed onshore northeastern Borneo, where they are juxtaposed against deep-marine shales of the Eocene Maliu Mudstone. On textural grounds (planar dolomites postdating compaction) and from the predominance of monophase aqueous inclusions, replacive dolomite rhombs and later dolomite cements appear to have formed at about 50–60jC and at shallow burial depths up to 0.5–1 km (0.3–0.6 mi). Isotopic and inclusion data indicate that the most likely dolomitizing fluid was dominated by Neogene seawater (for dolomites, d18OV-PDB = 5.9 to 10.3x; [consistent with the precipitation from southeast Asian Oligocene–Miocene seawater
{d18O = 1.5 to 4.2x} at temperatures of 40jC up to a maximum of about 50–75jC], 87Sr/86Sr = 0.708566–0.708697; from Tm = 2.1–3.4 wt.% NaCl). However, replacement and remobilization of the precursor limestone also contributed to the isotopic signature of the dolomites (87Sr/86Sr = 0.708115–0.708197),whereas an evolved formation water component cannot be ruled out. Dolomitizing fluids used faults and fractures as conduits to move into and alter the limestone,migrating farthest into themost permeable strata. The likely driver for fluid movement was convective flow caused by nearby Neogene igneous activity, perhaps in combination with tectonically induced hydrologic drive related to fault reactivation. Close to the main fault, late-stage dolomite cements occlude pore throats, reducing porosity (<5%) and permeability (<5 md). The best reservoir quality occurs in medium- to coarsely crystalline idiotopic mosaics of dolomite that have completely replaced the limestone 0.5–2 km (0.3–1.2 mi) away from the main fault where the late-stage cements did not form. These dolomites have 12–20% intercrystalline porosity and moderate to good permeability (tens of millidarcys). Fracturing has had variable impact on reservoir quality. Where late fractures remained open, permeability is enhanced (tens to hundreds of millidarcys), whereas brecciation and fault gouges result in sealing and reduced permeability. The textures, reservoir quality characteristics, and mechanisms of dolomitization show similarities to the few other detailed studies in the literature. This study refines the types of predictive reservoir models used in hydrocarbon exploration for subsurface faulted and dolomitized carbonates and increases the understanding of dolomitizing mechanisms of equatorial carbonates.
BLTN06086 Quantifying the origin and geometry of circular sag structures in northern Fort Worth Basin, Texas: Paleocave collapse, pull-apart fault systems, or hydrothermal alteration?Three-dimensional seismic data reveal numerous subcircular sag structures in the northern Fort Worth Basin. The structures are defined
by concentric faults that extend vertically upward 760–1060m (2500–3500 ft) from the Lower Ordovician Ellenburger Group. The largest structures remained active into the lower Desmoinesian Strawn Group. Criteria are outlined for defining seismically resolvable sag structures, and a detailed quantitative analysis of the geometries of these circular featureswas undertaken. Results are compared and contrasted, with reviews of subsurface collapse mechanisms and strike-slip processes that are known to produce subsurface circular to subcircular sag geometries in plan view. In this manner, we develop several constraints for differentiating collapse-related sag structures from strike-slip–related sag structures. Qualitative analyses indicate that the geometries observed are strongly analogous to subsurface collapse features where material is removed at depth to create a void, into which the overburden subsequently sags and collapses. Quantitative analyses support the formation of these features by incremental collapse and suprastratal deformation above a linked system of coalesced, collapsed paleocaves within the Ellenburger Group. Observations and criteria presented herein provide valuable information in defining seismically resolvable collapse features worldwide and help distinguish sag features of collapse affinity from those of other origins.
BLTN06087 A regional look at Morrow Formation gas in light of conflicting resource development in southeast New Mexico
Several factors have led to reservoir underdevelopment in the Morrow Formation in southeast New Mexico, including conflicting interestswith
potash development companies, government regulations protecting potash resources, lack of completions within successful wells, and lack of exploration. Over the past 70 yr, the Secretary of the Interior has set aside 777 mi2 (2012 km2) of southeastern New Mexico, referred to as the Secretary of the Interior’s potash area (SPA), to preserve potash resources.Oil and gas drilling are severely limited within the SPA, where leasing is managed by the Bureau of Land Management. The Morrow Formation reservoirs have significant undiscovered reserves in the SPA. Morrow Formation production-well density is roughly half that of the surrounding area, which may also be underdeveloped. Operators
have drilled a few directional wells to target Morrow Formation reservoirs while avoiding potash resources near the boundaries of the protected area, and they used horizontal wells to develop the shallower Brushy Canyon Formation in one area. Older abandoned wells within the SPA may be used in the future for drilling islands, but this practice has not yet begun. The purpose of this article is to provide structural and stratigraphic maps of Morrow Formation reservoir horizons, to present areas with future potential, and to suggest future development scenarios. The article also provides a regional Morrow Formation depositional picture and correlates this regional description to field-scale interpretations. The Morrow Formation is typically divided into two intervals: theMorrow clastics and the overlying Morrow limestones. The fluvialdeltaic
to shallow-marine Morrow clastic interval currently provides more than 40% of the natural gas production within the SPA. Depth to Morrow clastic production ranges from about 11,000 to approximately 14,000 ft (3352 to approximately 4267 m) in the SPA. This study divides the Morrow clastic interval into three informal subunits based on log character and uses flooding surfaces marked by correlatable bounding shales. The resulting net sand maps for these subunits indicate an overall transgression from deltaic to distributary-mouth bar or reworked deltaic to
deposition of overlying carbonates and marine shales. Trends of producing wells along depositional axes that are interpreted in this report indicate potential areas for future exploration and development. Future drilling will target depositionally complex reservoirs. The author recommends directional and horizontal drilling, aided by three-dimensional seismic imaging, to explore and develop SPA resources.
BLTN06132 Interpreting shoreline sands using borehole images: A case study of the Cretaceous Ferron Sandstone Member in Utah
To establish borehole image interpretation guidelines in a siliciclastic shoreline environment, this study used unique data from the Ferron Sandstone Member in Utah, where several core holes were drilled next to the outcrop cliff and logged with electrical borehole images. The guidelines include three main components: (1) differentiating depositional elements based on borehole image textures, (2)multiwell stratigraphic correlation and depositional architectures, and (3) ambiguity and data limitations. The stratigraphic interpretation of the image logs is closely correlated with the cores and the outcrops to evaluate the interpretation methodology. The sandstones of upper shoreface, middle shoreface, and channels are differentiated in each well based on a list of depositional textures and sequence characteristics revealed by the images and open-hole logs. The coals, carbonaceous shales, bay fill, and transgression lag deposits are identified as important elements in building the stratigraphic framework.Channels eroding into the shoreface and shoreface pinchout into delta plains are recognized based on the facies classification and stratigraphic framework. The shoreface progradation directions are drawn through multiwell sequence correlation, paleoflow, and seaward facies transition analysis. In the Muddy Canyon area, the progradation directions of the shoreface parasequences vary from north to east with dominance to the northeast. The complex channel systems with diverse flow directions amalgamated in the delta plains and eroded into the strand-plain shoreface sandstones inmost of the regression cycles. In the northern study area, the latest borehole image data revealed the south- or southeastward-prograding Ferron shorelines and the cyclic Blue Gate Member shoreline sequences. The integrated study supports the regional V-shaped Ferron shoreline with oblique delta progradations within the regional eastward transportation Structurainto the Mancos Sea.
BLTN06142 Structurally controlled hydrothermal dolomite reservoir facies: An overview: Discussion
One of the issues of the AAPG Bulletin (v. 90, no. 11) was concerned with ‘‘hydrothermal dolomite reservoirs,’’specifically ‘‘hydrothermal dolomite fields’’(Davies and Smith, 2006). The term ‘‘hydrothermal dolomite’’ is confusing and meaningless (Machel and
Lonnee, 2002). To study the origin of dolomite and its hydrothermal depositional setting, I examined modern settings, including the Mediterranean Sea (Friedman, 1991) (Figure 1). The shallow-water facies in this modern setting consists of dolomite and gypsum. The rocks range from almost pure gypsum to pure tough dolostone so thoroughly cemented that sampling required hammer and chisel. X-ray diffraction analysis indicates the presence of minor anhydrite. Sporadic aragonitic gastropods occur, but fossils are otherwise absent.Under the microscope, it is a peloidal micrite (dolomicrite).
BLTN07031 Structurally controlled hydrothermal dolomite reservoir facies: An overview: Reply
We welcome the comments by Friedman (2007) on our review article on structurally controlled hydrothermal dolomite. However, we disagree strongly with many of his comments and conclusions. We find it unfortunate that he repeats the statement of Machel and Lonnee (2002) that the term ‘‘hydrothermal dolomite’’is confusing and meaningless. Both the Machel and Lonnee (2002) article and the discussion by Friedman show a basic lack of understanding of the process of hydrothermal dolomitization and how common dolomite of structurally controlled hydrothermal origin appears to be worldwide.
