This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
The Prudhoe Bay field, located on the North Slope of Alaska, is the largest oil and gas field in North America. The main Permo-Triassic reservoir is a thick deltaic high-quality sandstone deposit about 500 ft thick with porosities of 15 to 30% BV and permeabilities ranging from 50 to 3,000 md. The field contains 20 109 bbl of oil overlain by a 35 Tcf gas cap. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).
The amount of trapped oil in hydrocarbon rich shale reservoirs recoverable through Enhanced Oil Recovery methods such as low salinity water flooding has been an ongoing investigation in the oil and gas industry. Reservoir shales typically have relatively lower amounts of swelling clays and in theory, can be exposed to a higher chemical potential difference between the native and injected fluid salinity before detrimental permeability reduction is experienced through the volumetric expansion of swelling clays. This fluid flux into the pore spaces of the rock matrix acting as a semi permeable membrane is significant enough to promote additional recovery from the extremely low permeability rock. The main goal of this paper is to determine how osmosis pressure build up within the matrix affects geomechanical behavior and hydrocarbon fluid flow. In this study we investigate Pierre shale samples with trace amount of organic content and high clay content as an initial step to fully understanding how the presence of organic content affects the membrane efficiency for EOR applications in shales using low salinity fluid injection. The same concept is also valid when slickwater is utilized as fracturing fluid as majority of the shale reservoirs contain very high salinity native reservoir fluid that will create large salinity contrast to the injected slickwater salinity.
The organic-rich reservoir shales typically have a TOC content of approximately 5 wt% or higher with TOC occupying part of the bulk matrix otherwise to be filled up by clays and other minerals. With less clay within the rock structure, the amount of associated clay swelling arising from rock fluid interaction will be limited. The overall drive of water into the matrix brings added stress to the pore fluid known as osmotic pressure acting on the matrix that also creates an imbalance in the stress state. The native formation fluid with salinity of 60,000 ppm NaCl has been used while 1,000 ppm NaCl brine is utilized to simulate the low salinity injection fluid under triaxial stress conditions in this phase of the study reported here. A strong correlation is obtained between the osmotic efficiency and effective stress exerted on the shale formation. The triaxial tests conducted in pursuit of simulating stress alteration under the osmotic pressure conditions and elevated pore pressure penetration tests indicated that the occurrence of swelling directly impact the formation permeability. These structural changes observed in our experimental results are comparable to field case studies.
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.
The Niobrara interval in the Denver-Julesberg (DJ) Basin contains several important unconventional hydrocarbon targets. However, the Niobrara is extensively faulted, which poses challenges for accurately landing and steering laterals in zone. Insight into small faulted structures in the Niobrara using traditional manual fault interpretation techniques is challenging because of the tuning thickness in seismic data. Fault throws less than the tuning thickness are difficult to interpret and incorporate into geosteering plans. Consequently, drillers frequently find themselves out of zone after crossing these small faults. Using independent information about fault locations and throws provided from multiple horizontal wells in the DJ Basin, this paper demonstrates the fault likelihood attribute (Hale, 2013) can resolve fault throws as small as 10 ft, allowing seismic-based well plans and unconventional project economics to be significantly improved.
Traditional geoscience data interpretation workflows in support of well planning can be tedious and time consuming, requiring manual fault picking on seismic profiles in conjunction with horizon tracing and gridding for structural mapping. The emergence of unconventional resource plays requires both more efficient geoscience workflows to support round-the-clock drilling operations and more detailed structural interpretations to help ensure laterals are steered along sweet spots. Pre-drill mapping of small-scale faults is therefore of particular importance for safe operations and helping ensure that lateral wells stay in zone.
Recent advances in fault-sensitive post-stack seismic attributes are changing the way subsurface professionals think about faults and how to map them in 3D space. In particular, the fault likelihood attribute (Hale, 2013) has provided a breakthrough improvement in the quality of seismic-derived fault attributes. Typically, the fault likelihood attribute is used in exploration settings to rapidly generate a broad-scale structural interpretation, being used both as a guide to manual fault interpretation and as input into automated fault extraction algorithms. This paper demonstrates the value of fault likelihood in development settings for assisting the well planning and geosteering process.
Little is known about the nature and origin of microcrystalline quartz in sandstone reservoirs or mudstone reservoirs. We have utilized advanced analytical capabilities to improve our understanding of controls on microcrystalline quartz development in several examples where porosity is preserved in deeply buried sandstone reservoirs to understand the development in siliceous mudstones.
In this study, several advanced analytical techniques were used to evaluate the crystallographic and compositional controls on the formation of microcrystalline quartz. SEM/Cathodoluminescence (CL) imaging confirms that quartz overgrowths have a complex growth history. Previous workers (Kraishan et al. 2000) suggested that CL patterns in quartz cement are largely due to trace elements rather than defects and that aluminum varies consistently between each cement phase. Electron Backscatter Diffraction (EBSD) combined with Wavelength Dispersive Spectrometry (WDS) confirms that the complex banding visible in CL is not due to changes in crystallographic orientation but more likely variations in quartz composition associated with changes in pore fluid composition and/or reservoir conditions. Secondary Ion Mass Spectrometry (SIMS) analysis provides maps of ultra-trace element distribution that confirm that trace amounts of iron, manganese, and titanium can be used as proxies for defect density and temperature. Additionally, SIMS analysis provides oxygen isotope data providing insight into the initial reservoir conditions and temperature of formation of microcrystalline quartz in several formations.
Microcrystalline quartz in the form of replacement, micropore, and overgrowth cements is present in the Wolfcamp A in the southern Delaware Basin. The amount of cementation has an effect on the reservoir quality and appears to have an impact on the petrophysical properties. The siliceous mudstones are comprised predominantly of biogenic silica (sponge spicules, radiolarians, which are the silica sources for the authigenic microcrystalline quartz), detrital grains (quartz and feldspars), pyrite framboids, and organic matter.
Integrating the results from these advanced analytical techniques has helped us develop our understanding of the processes controlling the formation of quartz cement and improved our ability to reconstruct the reservoir diagenetic history of quartz growth leading to a proposed model for predicting porosity preservation in deep, hot sandstone reservoirs and the formation of microcrystalline quartz in siliceous mudstones. This is the first research to report on spatially resolved isotopic analysis of silica cements integrated into a petrographic framework and a proposed mechanism for microcrystalline quartz growth.
In the Dunvegan Kaybob South Pool, recent multistage fracked horizontal wells have revealed the presence of a light oil play enveloping a large legacy gas field, developed with vertical wells. The boundary between the oil and gas producing areas intersect structural contours a high angle within deltaic sandstones of the Cretaceous Dunvegan Formation. To address controls on this boundary, a multidisciplinary study of cores, core analysis data, well logs was completed and integrated with test and production data to identify controls on fluid production.
Legacy gas production is from relatively high permeability delta front sandstones, while oil dominated production occurs from lower permeability, fine grained pro-delta deposits. While wells within the legacy gas field produce very low volumes of oil, core fluid extractions reveal significant oil is also present within this portion of the reservoir, but is not mobile. The Dunvegan clearly demonstrates permeability as the main control on the anomalous fluid distributions, with several other tight sandstone plays showing similar relationships, although often more subtle, such as observed in the Cardium, Montney, etc.
The anomalous fluid distributions with higher gas saturations in higher permeability beds and higher oil saturation in lower reservoir quality beds contradict conventional capillary reservoir charge models. Thus, we propose late stage migration of predominantly gas related to the increase in gas generation post peak oil window due to increasing maturity of the kerogen during burial. These late generated gas fluids migrated from the deeper part of the basin preferentially within higher permeability strata and fractures, and displace the earlier emplaced oil resulting in reservoirs with high GOR. These counterintuitive observations with higher liquids production from lower reservoir quality, can significantly improve the play economics and allow better prediction of fluid distribution in many plays.
Although unconventional low permeability reservoirs form laterally continuous thick hydrocarbon accumulations, they often have variable liquid saturations vertically and laterally. While varying kerogen type and maturity are important controls. In several plays, fluid distribution shows a strong correlation with permeability, with higher gas saturations occurring in more permeable beds. The control of permeability on anomalous fluid distribution has been discussed for several clastic, low permeability unconventional light oil and liquid rich gas plays in the Western Canada Sedimentary Basin (e.g. Wood and Sanei 2016, Venieri and Pedersen 2017). In this study we present a study of a legacy gas pool producing from deltaic sandstone reservoirs of the late Cretaceous Dunvegan Formation (Figure 1). The pool is located within the deep basin of western Alberta, an area of pervasive hydrocarbon saturation charged by enveloping thermal mature organic rich mudstones and coals (Masters 1984). The Dunvegan Kaybob South Pool is comprised of a lowstand delta lobe of the southward prograding Dunvegan Delta (Bhattacharya 1993).
Tomassini, Federico Gonzalez (YPF SA) | Smith, Langhorne (Taury) (SmithStrata) | Rodriguez, Maria Gimena (YPF SA) | Kietzmann, Diego (University of Buenos Aires - CONICET) | Jausoro, Ignacio (YPF Tecnología SA [Y-TEC]) | Floridia, Maria Alejandra (YPF Tecnología SA [Y-TEC]) | Cipollone, Mariano (YPF Tecnología SA [Y-TEC]) | Caneiro, Alberto (YPF Tecnología SA [Y-TEC]) | Epele, Bernarda (YPF Tecnología SA [Y-TEC]) | Santillan, Nicolas (YPF Tecnología SA [Y-TEC]) | Medina, Federico (YPF Tecnología SA [Y-TEC]) | Sagasti, Guillermina (YPF SA)
The objective of this work is to present the pore types and their relationship to the main core facies from the Vaca Muerta Formation, Neuquén Basin, Argentina. With an in-house methodology for focused Ion Beam scanning electron microscope (SEM) images and petrographic analysis, a linked to increase the understanding of the pore systems, mineralogy, diagenetic features, grain types and facies variations is carried out. Long continuous cores from two wells were described in detail by standard facies analysis and SEM for semi-quantitatively estimating total porosity, relative abundance of pore types and pore sizes, mineralogy, relative abundance of kerogen and migrated bitumen, type and origin of different clays, and diagenetic quartz abundance among other features. The SEM porosity, organic matter content and mineral distribution correlates favorably with independent measurements obtained by other labs methods. The findings were linked to the core descriptions and the regional sequence stratigraphic framework to predict best reservoir facies. This prediction is done with the production results for each horizontal well in the different landing zones. Finally, the understanding of the pore system can be used to define the best areas and intervals where horizontal wells can be geosteered during the development stage of a block.
The Tithonian-Valanginian (Upper Jurassic-Lower Cretaceous) Vaca Muerta Formation is the main source rock of the Neuquén Basin (Figure 1). The Vaca Muerta Fm. is a lower slope and basinal facies equivalent to the updip Quintuco and Loma Montosa Formations. This formation is a very appealing target for unconventional development due to its vast lateral extent, great thickness (up to 500 m – 1640 ft), relatively high values of total organic carbon (TOC 2-10 %), thermal maturity (oil to dry gas windows), mineralogical composition (less than 30% clay), overpressure and relatively simple structural setting. The study area is located in the center of the Neuquén Basin (Figure 1), north of the Huincul high and mainly in the Añelo depocenter where major activity is taking place. More than 600 horizontal wells have been drilled in the basin in different landing zones resulting in different hydrocarbon production. The EIA (2013) estimated that the technically recoverable resources estimated for this formation are in the order of 300 Tcf of gas and 16 Bbbl of oil and these numbers may be low.
Regueira, Teresa (Center for Energy Resources Engineering [CERE], Technical University of Denmark) | Sandoval, Diego (Center for Energy Resources Engineering [CERE], Technical University of Denmark) | Stenby, Erling (Center for Energy Resources Engineering [CERE], Technical University of Denmark) | Yan, Wei (Center for Energy Resources Engineering [CERE], Technical University of Denmark)
Confinement by tight pores can influence fluid phase behaviour according to some recent investigations. Most of these studies are theoretical and the experimental investigations are relatively scarce. In this work, we have employed the calorimetric approach to study the equilibrium of n-alkanes confined in two synthetic porous materials with a narrow pore size distribution, not only at atmospheric conditions but also at elevated pressures. In addition, we also measured two chalk samples from the Danish North Sea in order to shed light on whether the tight chalk formation will influence the phase behaviour. A shift in the saturation temperature of the confined fluids was observed when confined in the synthetic porous materials, whereas no temperature shift was observed in the fluid confined in the chalk powders. By using phase equilibrium calculation incorporating capillary pressure difference between the gas and liquid phases, we also predicted the temperature shifts and compared them with the experimental values.
The influence of porous media on phase behaviour is a topic discussed in the oil industries for decades with revived interests and investigations in recent years due to its potential impact on production from tight shale. For the tight chalk formation in the North Sea, a similar question on the role of porous media in phase behaviour has been frequently asked. Some recent experimental and modelling methods developed for shale may help answer the question.
The Lower Cretaceous chalks in the Danish Central Graben have porosities in the range from 15 to 45% with a very small average permeability, lower than 1 mD. The current production from these reservoir rocks in the Danish Central Graben happens in the Valdemar field, which is a very complex and heterogeneous reservoir with a low and uneven production (Jakobsen et al. 2005). It is expected that in this tight rock the reservoir fluids are subjected to a high degree of confinement. The interaction between the fluid and the pore wall is significant, and there is always a question whether the phase behaviour in the tight formation will be dramatically changed. In principle, the phase behavior of confined fluid can be altered due to large capillary pressure differences, selective adsorption, and extreme reduction in the free space of movement. These effects result in changes of fluid physical properties and shifts in saturation pressures/temperatures. When such differences are taken into account into reservoir simulation studies, well performance, gas-oil ratio, oil and gas production rate, and ultimate recovery may be affected. (Wang et al. 2014, Teklu et al. 2014, Dong et al. 2016, Firincioglu et al. 2012)