The goal of this work is to present a new type of unconventional play (carrier bed/halo) that is developing in the Powder River basin. This play is being developed via the combined technologies of horizontal drilling and multistage hydraulic fracturing. The Turner sandstones of Turonian age is a target of exploration and development in the Powder River basin. The sandstones are interpreted to be marine shelf sands. The Turner Sandstone is a prolific reservoir in the Crossbow area of the Powder River Basin. The area is being developed with horizontal wells at vertical depths of 9400 to 12000 feet. Initial production from horizontal wells ranges from 500 to 1700 BOPD and 1000 to 4000 MCFGPD. The carrier bed (halo) play is downdip and an extension from older vertical Turner production in the School Creek, Porcupine, and Tuit Draw fields. The Crossbow area is overpressured with no known water contacts (updip or downdip). The Crossbow area includes the Crossbow, K bar, Mary Draw and Horse Creek fields which have now merged into a larger producing area. Source beds for the Turner Sandstone include the overlying Niobrara, and Sage Breaks shales and underlying Mowry, Belle Fourche, Greenhorn, and Poole Creek shales. Source bed maturity occurs in the deeper part of the basins. Oil and gas migration into the carrier beds results in regional pervasive hydrocarbon saturation. Discrete traps that have been previously developed are part of a more extensive hydrocarbon system and ultimately may merge into an extremely large area of continuous production. Introduction The Powder River Basin is one of the most prolific hydrocarbons producing basins in the Rocky Mountain Region. Cretaceous producing formations include the Dakota, Muddy (Newcastle), Turner, Frontier, Niobrara, Shannon, Sussex, and Parkman. Permian age Minnelusa sandstones are also productive in the northern Powder River Basin. Recent horizontal drilling activity is targeting the Mowry, Frontier, Turner, Niobrara, Sussex, Shannon, and Parkman.

Abstract The Niobrara Total Petroleum System (TPS) covers an extensive area across the Rocky Mountain Region, USA. In the Powder River Basin (PRB), the petroleum system consists of source beds in the Upper Cretaceous Niobrara Formation as well as reservoirs in the Upper Cretaceous Frontier, Turner, Niobrara, Sussex, Shannon, Parkman, Teapot, and Teckla, and Paleocene and Eocene Fort Union and Wasatch formations, respectively. The Niobrara is a deep-water hemipelagic carbonate mudrock and will be the subject of this paper. The Niobrara in the southern PRB is Coniacian to early Campanian in age and approximately 150 to 650 ft thick. The formation, where productive, has low porosity (< 10﹪), low permeability (<0.01 md), and pore throat sizes less than 0.1 micron. The immature-mature present-day depth boundary is approximately 8,000 ft. The formation is subdivided informally into three units in the PRB (A, B, and C). The units consist of cycles of marls and chalks. The main reservoir target is the B chalk/marl zone. Geologic factors related to successful exploration and development include excellent source-rock quality, source-rock maturity, reservoir thickness, matrix and fracture porosity and permeability development, high geothermal gradients, overpressure, oil gravity, gas-oil ratios, and regional fracture development. Recent drilling success utilizing horizontal drilling and multi-stage hydraulic fracture stimulation suggest the opportunity for a large (giant) unconventional petroleum accumulation. Introduction The Niobrara Formation in the southern PRB is an emerging continuous hydrocarbon play. The accumulation covers a large area and is a potential giant accumulation. Recent drilling success by several operators indicates that productive reservoir conditions exist in the southern PRB (Figure 1). In this area, the Niobrara Formation consists of three marly chalk facies, informally referred to in descending order as A, B, and C benches that are separated by marls, similar to the Denver Basin (Figure 2). The basal Fort Hays Member of the Niobrara Formation is absent in the southern PRB (Weimer and Flexer, 1985; Taylor, 2012).

Abstract High-resolution scanning electron microscopy (SEM) has been widely applied to understand the mechanism for oil/gas storage in the unconventional shale reservoirs. However, the microstructures in the Upper Devonian-Lower Mississippian Lower Bakken and Pronghorn members of the Bakken Formation are poorly understood in the context of petrography. This project used SEM to investigate the pore types, porosity development, and their variability as functions of mineral composition, organic-matter type, total organic carbon (TOC) content, and thermal maturity in the Lower Bakken and Pronghorn members. Eleven representative organic-rich rock samples from nine wells, spanning across the Williston Basin, have variable levels of maturity from immature (Tmax=422.5°C, equivalent calculated vitrinite reflectance Ro=0.45%) to late mature (Tmax=453.7°C, equivalent cal. Ro=1.0%). These samples also have a broad range of TOC values from approximately 0.5 to 23 wt.%. Three pore types were recognized in this study: mineral matrix pores, organic-matter pores, and fractures. Common mineral matrix pores include interparticle pores (e.g., pores between clay platelets and pores at the edge of rigid grains) and intraparticle pores (e.g., pores in dolomite, framboidal pyrite, and microfossil-cavity). The size of these pores varies from 10 nm to no more than 8 μm. Our results suggest that an increase of mineral matrix porosity appears to be related to higher clay and dolomite content. The nanometer-sized organic matter pores are predominantly preserved in the amorphous organic matter, and they are most abundant in the immature and latemature shales. On the other hand, structured kerogens (e.g., Tasmanites and terrestrial phytodetritus) are typically non-porous regardless of thermal maturity. The integration of petrographic features and thermal maturity data can assist in distinguishing between kerogen and migrated oil/bitumen. Care should be taken to interpret the shrinkage pores within organic matter as evidence shows that some shrinkage pores are filled with calcite, reflecting a reducing volume of kerogen during oil/bitumen generation. The presence of fractures is implied by the crack-filling migrated bitumen/oil as a consequence of the overpressure caused by thermal decomposition of kerogen. This study demonstrates that there is no single, universal relationship between TOC and organic porosity for all samples. We also conclude that a vanishing volume of organic matter pores from immature to early mature Bakken shale samples, followed by a general increase of organic porosity in peak and late maturity windows.

Abstract The marine oil-prone lower and upper Bakken shales are world class source rocks in the Williston Basin, which are a significant element for the Bakken Petroleum System (BPS) and sourcing reservoirs in the middle Bakken, upper Three Forks, and lower Lodgepole formations. A good understanding of the thermal-burial history of Bakken shales is essential to achieve realistic charge history, which closely relates to Bakken oil presence in reservoirs of BPS across the Williston Basin. The oil-generation kinetics is one of the most important thermal dynamic parameters. The maturation of immature Bakken shales under a hydrous closed-system setting was implemented by the method of hydrous pyrolysis (HP) in a temperature- and time-series of order. This method provides a conceivable analogue for natural oil generation and expulsion. The derived kinetics for Bakken shales includes activation energy at 53.79 kcal/mole and frequency factor at 1.25×10 27 m.y. −1 for an oil-generation reaction. These kinetic parameters were tested in a well constrained 1-D thermal-burial history model. The modeled extent of oil generation correlates well with transformation ratios of Bakken shales from independent analysis. The HP oil-generation kinetics were also applied to other thermal-burial histories in the basin, and further modeling results indicate very minimal oil generation from Bakken shales in the Parshall Field and early oil generation in the Sanish Field. This agrees with measured thermal maturity indices and transformation ratios determined by atomic H/C ratios of isolated kerogens for those areas. The discovery of significant oil reserves in the Parshall/Sanish area implicates that, instead of charging from in-situ Bakken shales, the majority of discovered oil may have been laterally migrated from more mature down-dip Bakken shales adjacent to the Parshall/Sanish area. Introduction The lower and upper Bakken shales of the Bakken Formation, one of the world-class marine oil-prone source rocks, were deposited from the Late Devonian to Early Mississippian in the Williston Basin, which is an intra-cratonic sedimentary basin (Figure 1). The Nesson, Cedar Creek and Billings anticlines are major structures in the basin.

Abstract The Niobrara Formation consists of deep-water chalks and marl units in the Denver Basin. Chalk units are generally considered the reservoir rock while the marls contain higher total organic carbon (TOC) contents and are considered the source beds. Chalk and marl units consist of microscopic coccoliths, forams (dominantly pelagic), inoceramus and oyster fossils, kerogen, clay, silt, and fish bones. Chalks have 70% and above carbonate content whereas the marls range in carbonate content from 30 to 70%. Kerogen, clays and silt comprise the remainder of the mineralogical composition. The Niobrara is subdivided into two members: Smoky Hill and Fort Hays Limestone. The Smoky Hill is informally divided into A, B, C intervals in descending order. The chalks are separated by marl intervals. Dramatic thickness changes occur in the chalk and marl units in Wattenberg Field. Thickness variations result from subaqueous erosion over topographic highs, onlap and downlap of various units indicating bottom current activity and topography, convergence of section (i.e., higher rates of sedimentation in one area compared to an adjacent area) and compensatory deposition. Many of these causes of thickness variations can be related to intrabasin basement structural movement or differential sedimentation. The most significant erosional event removes the A chalk and parts of the A marl over an interpreted west-east paleostructure (the ‘Wattenberg High’). Differential sedimentation patterns may arise from bottom current activity either filling in topographic low areas or creating subaqueous barlike features. Understanding stratigraphic architecture is paramount in targeting chalks and calculating reserves in the Niobrara Formation. Chalk thickness varies dramatically across the field. Thickness variations in the marl units is also important to understand in that the source bed capacity is a function of marl thickness and TOC content. Small scale clinoforms may be present in the C marl interval. Onlap of A marl units onto the Wattenberg High also changes source rock capacity. Introduction The most important mineral extraction activity over the past 50 years in Colorado has been the discovery and development of Wattenberg Field (Figs. 1, 2). The Wattenberg Field is located northeast of Denver, CO and produces oil, gas, and condensate from the following Cretaceous horizons: Dakota-Lakota, J Sandstone, D Sandstone, Greenhorn, Codell, Niobrara (A, B, C, and Fort Hays), Hygiene, Terry, and Larimer-Rocky Ridge.

The Upper Cretaceous Codell Sandstone is a major pay in the giant Wattenberg Field of the Denver Basin. Vertical well completions in the Codell date back to 1981 and were hydraulic fracture stimulated. The vertical wells also have a history of successful hydraulic refracturing. New horizontal wells (2011 to P) with initial production of 100 to 700 BOPD (GOR ~10,000 cf/bbl) indicate substantial remaining reserves in the formation. Geologic factors important for production include: proximity to thermally mature source beds; thickness; geothermal gradients; pressure gradients; fault bounded reservoir compartments; gas- oil ratios; sufficient reservoir quality (phi-h). The Codell in Wattenberg is characterized by low porosity (<12%) and permeability (< 0.1 mD). The Codell is 5 to 20 ft thick across the Wattenberg Field and has formation pressure gradients that range from 0.45 to 0.66 psi/ft. Geothermal gradients range from 1.8 to 3 o F/100 ft. The highest GORs in the field correspond to the highest geothermal gradients. The sandstone is very fine to fine grained and bioturbated. Thin (< one ft thick) hummocky cross stratified beds are present in the Codell. Depositional environment is interpreted to be a shallow marine shelf setting. Clay content within the pay interval is approximately 20% and consists of 40-45% mixed layer illite-smectite, 30-40% illite, 10-30% chlorite, and up to 7% glauconite. The Codell is a low-resistivity, low-contrast pay. The fault-bounded reservoir compartments form mainly from a well-developed polygonal fault system. Polygons are generally about 1.5 square miles in size. The orientation of the polygons is influenced by pre-existing basement fault systems. The Codell unconformably overlies the Fairport chalk member of the Carlile Formation and is unconformably overlain by either the Juana Lopez or the Fort Hays Limestone Member of the Niobrara Formation.

The lower and upper Bakken shales are world class source rocks in the Williston Basin, sourcing reservoirs in the Bakken, upper Three Forks, and lower Lodgepole formations, which comprise the economically significant Bakken Petroleum System (BPS). 10 to 400 billion barrels of oil have been estimated to have been generated from the Bakken shales, charging both unconventional and conventional plays in the BPS, but an advanced geochemical and geological characterization of source rock property of Bakken shales enables more realistic oil resource estimation. The technical contribution of this study enhances our understanding of the source rocks' potential and sequence stratigraphy of Bakken shales and the associated relationship with Bakken oil presence in reservoirs of the BPS across the basin. Over three thousand total organic carbon (TOC) content and other geochemical results, such as kerogen type, maturity, and kinetics, have been analyzed at the Source Rock Analysis Lab of Colorado School of Mines. The correlations of wireline logs, geochemical TOC and hydrogen index (HI) logs, XRF mineralogy- associated elemental logs have been integrated to infer depositional paleo-redox conditions and establish sequence stratigraphy for the Bakken shales. The results indicate that lower and upper Bakken shales exhibit a wide range of TOC content, and the kerogen present in shales is primarily Type II kerogen. Original HI and TOC across the basin are restored and averaged at ~580 mg HC/g C and ~19-20 wt.%, respectively. The pyrolysis Tmax temperature of 425°C, production index of 0.08, and conversion fraction of 0.1~0.15, correspond to a threshold of incipient bitumen generation from early mature shales. Lower and upper Bakken shales also exhibit vertical recurrent patterns in the TOC, GR and silicon logs, which may result from mixed effects of the original depositional environment and process and the progressive post-depositional diagenesis and catagenesis. The maximum flooding surface was identified near the top contact of lower and upper Bakken shales, indicated by the highest enrichments of Vanadium and Nickel from XRF logs. Overall, the upper and lower Bakken shales in the central basin are organic rich, contain oil-prone kerogen, and are thermally mature and in the oil generation window, with very prolific oil-generation potential.

The Three Forks Formation is an important part of the Bakken Petroleum System of the Williston Basin. The USGS estimates that 3.7 billion barrels and 3.5 trillion cubic feet of gas can be technically recovered from the Three Forks. The formation is currently being developed with horizontal drilling and multi-stage hydraulic fracturing. Many geological and technological factors control production. The principal source bed for the Three Forks is the Lower Bakken Shale (LBS). Source rock maturity is a primary control on the extent of Three Forks production across the basin. Poor, if any, production exists outside the maturity boundary. Other geologic factors controlling production include matrix and fracture porosity and permeability, depositional environment, reservoir facies, overpressure, structure, mechanical stratigraphy, and thickness. Technology factors controlling production include lateral length, number of hydraulic fracture stages, proppant volume and type, and well spacing. The Three Forks is a very fine-grained to silty dolostone unit with interbeds of dolomudstone and anhydrite. Siliciclastic content ranges from 10 to 40%; dolomite content ranges from 20 to 60%; clay content is low in the dolostones (<10%) but increases in the dolomudstone units (>30%). The depositional environment of the Three Forks ranges from subtidal to supratidal. This peritidal sequence is clastic dominated with no or very little microbial carbonates being observed. The dominance of silt-sized dolomite, quartz, and feldspars suggests transportation of silt-sized material by streams and/or wind into a tide flat and then reworking by tidal energies. A portion of the dolomite may be detrital. Bi-directional ripples, wave ripples, mud cracks, mud drapes, and flaser to lenticular bedding all support the tidal interpretation. Much of the lower and middle Three Forks is deposited in a highly oxidizing continental to coastal environment. This interval is characterized by intense red color resulting from hematite staining of clastic material. Anhydrites (nodular, bedded, and disseminated) are common. Anhydrites increase in abundance in the lower Three Forks. The anhydrites are nodular "chicken-wire" types which were deposited in coastal to supratidal sabkhas. Thin layers of anhydrite or coalesced nodules occur in more landward parts of the sabkha. Some halite content (1-2% XRD) is present throughout the Three Forks which supports the strongly evaporitic environment interpretation. Producing reservoir facies have porosities which range from 5 to 10%; permeabilities are generally less than 0.05 md. Microfractures are common in the reservoir facies. The upper Three Forks unit is the primary objective; however, newer wells are also completing in the middle or second Three Forks unit suggesting additional reserves. Faults and fracture corridors may provide migration pathways to middle and lower Three Forks units. Lateral length and fracture stimulation stages vary from operator to operator.

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: Force of petroleum expulsion creates sites of opportunities in the form of bedding-parallel fractures; Thin film of supersaturated solution in-fills these sites of opportunities; Mineral crystals utilize the site of opportunities and use them as sites for precipitation; Crystal growth exerts pressure creating force of crystallization; 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. The zone of intense beef-fracturing corresponds to the most organically rich and mechanically anisotropic intervals. The minimum petroleum-generation pressure required for initiating bedding-parallel expulsion fractures was calculated, plotted and correlated with "beef fracture" intensity and mechanical anisotropy. A good correlation was observed. Five distinctive attributes are recognized as being associated with the existence of pervasive "beef fractures" in shales: 1) organic-richness, 2) thermal maturity, 3) overpressuring, 4) mechanical anisotropy and 5) calcareous material in the shales (e.g., coccoliths in the Mesozoic examples).

Abstract The impact of petroleum-expulsion fractures on productivity of the Bakken shales were investigated by integrating epifluorescence petrography, pressure transient analysis and analysis of petroleum-expulsion fracturing. In early exploration vertical wells, drilling breaks from ten minutes to one minute per foot with gas increases from ten units to several hundred units were considered poor shows in the source rocks of the Bakken shales. Drill Stem Tests (DST) over the Bakken shales were reported with average production rates that reach several tens of barrels per day. These shales were overpressured with no matrix porosity in evidence and permeability in the micro Darcy scale. Production was assumed to come from fractures. Speculative conclusions were drawn about these fractures to be related to source-rock maturity, petroleum expulsion and overpressuring. These conclusions were a significant promoter for exploration in the Bakken Formation. Those speculative conclusions have encouraged to review a total of 64 Drill Stem Tests (DST) over different intervals that include the Bakken Formation and/or the underlying three Forks Formation. Resistivity logs, cores and thin sections were studied to conduct an integrated geological interpretation for pressure transient behaviors of the Bakken shales. The study highlights that the Bakken shales are naturally fractured and can be interpreted on resistivity curves separation. The Three Forks and Middle Bakken pressure transient behaviors imply spherical flow which indicates that there is always contribution from the Bakken Shales. The Bakken pressure transient behavior shows dual porosity flow (naturally fractured) with low fracture system's storativity (λ) implying that fluid is mostly stored in the matrix. The study also suggests that the matrix gives up its fluid rapidly to the fracture system indicating high interporosity flow (ω) and implying that petroleum-expulsion fractures contribution is present. The significance of petroleum-expulsion fractures resides in its ability to provide higher permeability pathways through the Bakken shales, and explains their high deliverability. The volume expansion due to petroleum generation is invoked as a mechanism to increase pressures to levels of inducing expulsion fractures responsible for primary migration of petroleum and forming the Bakken unconventional pervasive petroleum system.

The Codell Sandstone is a low-resistivity, low-contrast pay in parts of the northern Denver Basin. The area of new oil and gas production is in the deeper part of the basin between the Silo and Wattenberg fields of Wyoming and Colorado, respectively. Thickness of the Codell averages 15 to 20 ft in this area. The cause of the low resistivity is clay and pyrite content. Cores of the Codell illustrate that the sandstone is low permeability, low porosity, bioturbated and reworked finegrained marine shelf sandstone. The Codell is the upper member of the Carlile Formation and unconformably overlies the lower Carlile shales or the Greenhorn and is unconformably overlain by the Niobrara Formation. The Niobrara, lower Carlile, and Greenhorn formations are important source beds for the Codell in the Denver Basin. All are regarded as Type II sapropelic source rocks. Keys to new production are source rock maturity, horizontal drilling, and multistage fracture stimulation. Sweet spot areas coincide with high heat flow, high gas-oil ratios, overpressuring, and natural fracture development.

The Upper and Lower Bakken shales are the source beds for the Bakken Petroleum System of the Williston Basin. Reservoirs for this system include the shales, the lower Lodgepole, Middle Bakken silty dolostones, Pronghorn dolostones, and Three Forks silty dolostones. The Upper Shale was a drilling target in the late 1970s through the early 1990s in southwest part of the basin in North Dakota (termed the depositional limit play or Billings Nose play). The discovery of the giant Elm Coulee Field in Montana changed drilling strategies to focus on the Middle Bakken dolostone member. As this play extended into North Dakota, drilling success was also encountered in the upper Three Forks dolostones. The Upper Bakken Shale has recently been targeted with horizontal drilling and multistage fracture stimulations along the southwest edge of Elm Coulee Field where the Middle Member pinches out. In this area wells are drilling into the Upper Shale and then completed with multistage hydraulic fracture stimulations. The fracture stimulations extend into the adjacent Lodgepole and Three Forks formations. So in essence, these new wells target multiple pays. Factors thought to be important in this Upper Shale play include: orientation of horizontal laterals, bed thickness, natural fractures, shale mineralogy, abnormal pressure, and TOC content. This play is a similar to the previous depositional limit play in North Dakota except the wells are completed with multistage fracture stimulations. Exploration success in the Upper Bakken shales suggests that future drilling should also target the Lower Bakken Shale.

Abstract A great variety of factors can influence production, and it is often difficult to discriminate how significant the impact of a single factor is. The unconventional nature of the Bakken tight oil play requires considering both geological and technological aspects, as completion designs evolved at a rapid pace over recent years. Based on an integrated and correlative approach this study aims to understand why certain areas in the Bakken play are considerably more productive than others, and to identify the responsible factors. The Late Devonian to Early Mississippian Bakken Formation in the Williston Basin is a world-class petroleum system and represents the most prolific tight oil play known to date. The source rocks in this unconventional system are the highly organic-rich Lower and Upper Bakken shale members. The silty, dolomitic Middle Bakken member, sandwiched in-between the shales, and upper Three Forks member, underlying the Bakken Formation are the main target horizons for production. The Bakken is a technology-driven play and a clear trend of increasing production rates over time is evident as drilling techniques and the completion design of wells are progressively becoming more sophisticated. Latest since 2010 the majority of operators employ massive hydraulic fracturing treatments with up to 40 stages and millions of pounds of proppant. However, numerous older wells outperform younger wells despite technological advancements, suggesting that geological factors have a larger impact on production than the completion design. Geological factors influencing productivity can reach from reservoir quality and thickness, over structural and stratigraphic framework, rock-mechanical properties, natural fractures, to pore-overpressure distribution and organic geochemical parameters. The interplay of hydrocarbon generation potential and maturity results in tremendous overpressuring, and creation of fracture permeability and secondary porosity. A combination of overpressure- and buoyancy-driven migration of hydrocarbons into up-dip located traps can result in large-scale accumulations, as for example Sanish-Parshall and Elm Coulee. The comprehensive and integrated analysis of technological and geological data allowed identification of different Bakken play types, which are productive for different reasons. The knowledge and understanding of where and why sweetspot and low productivity areas occur is invaluable for both current development and future exploration. URTeC 1596247

Summary The Three Forks Formation is becoming increasingly important in terms of hydrocarbon productivity in the Williston Basin, North Dakota. This growth has been attributed not only to the availability of new drilling and completion techniques, but also to the availability of new geological information. Core data has allowed the understanding of depositional environment, facies distribution, and other aspects that impact the reservoir quality. The description carried out on 6 cores and analysis of characteristics and evidence in additional 23 wells, indicates that the Three Forks Formation was deposited in a very shallow and extensive epeiric platform. The arid climate dominant during the late Devonian, in combination with changes in sea level, provided the right setting for the development of an evaporitic platform and deposition of storm/tidally dominated lithologies, in the sedimentary record. All these conditions together, pose a unique setting for the sediment deposition and impact the reservoir quality, due to the unusual hydraulic conditions in this kind of environment. One of the most challenging aspects in the definition of reservoir quality in carbonate tight reservoirs is the characterization of porosity and permeability due to the complexity of these types of rocks. A methodology that has been proven to be accurate for the definition of flow units in conventional reservoirs, using core data analysis, was carried out in these tight rocks, in order to establish a relationship between facies distribution, flow units and well log response. This definition was done using the SML methodology (Stratigraphic Modified Lorentz Plots). This methodology was introduced by Gunter et al. (1997) and illustrates in a very simple way the variability of reservoir storage capacity and flow capacity by the interpretation of slope changes on the plot. In North Dakota, a series of wells (20), with core data analysis available were plotted under this methodology in order to obtain an image of the flow units slope's trends and distribution. As a preliminary result, all the wells show in general a very accurate response between facies, SML plots and hydrocarbons saturation. Some assumptions about reservoir quality in intervals not tested can be done due to the behavior in the slopes. The slopes obtained in the Upper Three Forks productive interval (around 45 degrees) are present in other intervals within Three Forks Formation as with the Middle and Lower Three Forks. Additional cross plots based on core data like porosity vs. permeability and irreducible oil saturation vs. irreducible water saturation plots have showed being a good approach in the definition of reservoir quality in this unconventional reservoir type. URTeC 1600752

Introduction The Bakken petroleum system is an unconventional tight oil play containing both source and reservoir rock, with continuous saturation throughout much of the Williston basin in North Dakota and eastern Montana. With a continuous-type accumulation, and increased thickness of a source and/or reservoir rock can mean an increase in hydrocarbons generated and expulsed from the source rock, and/or an increase in storage capacity within the reservoir rock. For this, and other reasons yet to be presented, thickness anomalies within the Bakken and Three Forks formations are of great interest to hydrocarbon exploration and production in the Williston basin. Thickness anomalies have long been recognized in Devonian and Mississippian strata of the Williston basin in North Dakota and Montana, and the Canadian provinces of Saskatchewan and Manitoba. Dissolution of Prairie salt, collapse of overlying beds, and infill of the resultant accommodation space has been cited as one mechanism for the creation of thickness anomalies in the Williston basin (Anderson and Hunt, 1964; Demille et al., 1964; Holter, 1969; Langstroth, 1971; LeFever and LeFever, 2005; Oglesby, 1988; Parker, 1967). Several of these collapse structures form productive hydrocarbon traps. Fields such as Hummingbird field (Saskatchewan) and Outlook field (Montana) are examples of hydrocarbon traps within dissolution-collapse structures. Additionally, over-thickening of reservoir rock at Elm Coulee and Dickinson fields has been attributed to Prairie salt dissolution (LeFever et al., 1995; Sonnenberg and Pramudito, 2009). These examples not only highlight the importance of thickness anomalies for hydrocarbon exploration and production, but also the importance of Prairie salt-dissolution collapse structures. Study Area The study area is located in north central North Dakota (Figure 1.1), and covers approximately 460 townships in Renville, Ward, Bottineau, McHenry, Rolette, Pierce, Towner, Benson, Sheridan, and McLean counties. Well logs were used from 186 wells within the study area that penetrate the Bakken or deeper strata to construct subsurface maps and cross-sections. This study area was chosen because it encompasses a cluster of thickness anomalies in the Bakken and Three Forks formations at or near their eastern zero edges. URTeC 1617728

Abstract Most published models for the Marcellus shale of the Appalachian basin show a great bias towards the Black sea depositional model for black shale sedimentation. Such an approach implies that organic-rich Marcellus shale facies were deposited in dysoxic to anoxic conditions in deep water environments. Recent sedimentological and stratigraphic work involving eight core data, over 100 thin sections, SEM and XRD data, field studies of Marcellus shale exposures in New York and Pennsylvania as well as over 800 electrical wireline logs, however, suggest that such a paleobathymetry-driven depositional model may not necessarily be appropriate for the Marcellus shale. The occurrence of sedimentary structures such as starved ripples, graded beds, bioturbation, burrows, reworking of authigenic minerals like pyrites, aligned fossils, basal fossil lag deposits and the presence and enrichment of silt grains even in organic-rich facies, while not indicative of the water depth, were all interpreted to be indicative of current activity. Total organic carbon (TOC) content was found to increase from the eastern margins of the basin towards the western craton-ward side of the basin. This can be attributed to the increased clastic influx to the east as a result of increased sedimentation rates from the Catskill delta. Marcellus black shale facies were thus probably deposited in a bathymetrically subdued setting akin to present-day continental shelves and not in the deepest part of the basin. In Marcellus times, such a setting occurred towards the western side of the Appalachian basin, away from the Acadian Mountains. The key controls on Marcellus Shale deposition in such settings would be a combination of local geologically rapid subsidence/uplift events, seasonal variations in nutrient sourcing of algal blooms, changes in salinity and clastic influx rates, rather than water depth. Thus, organic-rich laminated Marcellus Shale lithofacies would have been deposited during periods of increased algal bloom and reduced clastic influx, increased organic preservation as a result of changes in bottom water chemistry to favor the deposition of organics and siliciclastics over carbonates. The less organic-rich Marcellus Shale lithofacies in turn were deposited during periods of episodic tectonic quiescence, increased dilution of organic matter as a result of increased clastic influx from the Acadian Mountains. In the same way, the interbedded limestone facies were deposited during times of reduced algal bloom, low sedimentation rates and changes in bottom water chemistry to favor carbonate deposition over deposition of organics and siliciclastics. URTeC 1563700

Abstract The Niobrara is one of nine horizons that are productive in the giant Wattenberg Field area (GWA) of Colorado. GWA covers approximately 3200 square miles. The field was discovered in 1970 (J Sandstone) and first significant Niobrara production was established in 1976 from vertical completions. Horizontal Niobrara drilling began in the field in 2009. Wattenberg straddles the Denver Basin synclinal axis and is regarded as a basin-center petroleum accumulation. The Niobrara is overpressured and drilling depths are 6200 to 7800 ft. The Wattenberg area is a " hot spot" or positive temperature anomaly. Temperature gradients range from 16 - 18°F/1000 ft on the edges of the field to about 28 to 29°F/1000ft in high GOR areas. The Niobrara consists of four limestone (chalk) units and three intervening marl intervals. The lower limestone is named the Fort Hays and the overlying units are grouped together as the Smoky Hill member. The chalk units are referred to in descending order as the A, B, C, and Fort Hays. Erosional unconformities exist at the top and base of the Niobrara. The upper unconformity removes the upper chalk bed in some areas of the Wattenberg Field. The B and C chalks are the main focus of horizontal drilling by operators in the field. The underlying Codell Sandstone/Fort Hays is also targeted with horizontal wells. Recent horizontal completions have initial production of approximately 100 to 700 BOPD with a GOR of 500 to 10,000 cu ft per barrel. Estimated ultimate recovery per well is greater than 300,000 BOE. The Wattenberg area has a resource estimate from the Niobrara of 3–4 billion barrels equivalent. The combined technologies of horizontal drilling and multistage fracture stimulation have brought significant new life into this 43 year old field. URTeC 1562913

Abstract Recent published attempts at developing a sequence stratigraphic model for the Marcellus Formation of the Appalachian basin show a bias towards the Black Sea depositional model for black shale sedimentation. Such an approach ultimately leads to the conclusion that the organic-rich facies of the Marcellus shale were deposited in dysoxic to anoxic conditions found in deep water environments. It is evident, however, from textural analysis that while some of the Marcellus shale lithofacies were probably deposited by suspension settling out of low-energy buoyant plumes, others were very likely deposited by sediment dispersal mechanisms that involved a combination of storm-winnowing and re-suspension, gravity-driven processes and storm-driven unidirectional currents in a more bathymetrically subdued setting, where the key controls on black shale sedimentation will be tectonics, nutrient sourcing of algal blooms, substrate and clastic influx rates, rather than water depth as implied by the Black Sea model. This paper is thus an attempt at a review of the sequence stratigraphic framework of the Marcellus shale based on an approach that defines cyclicity without bias towards any particular depositional model. Over 100 thin sections, SEM and XRD data, field studies of Marcellus shale exposures in New York and Pennsylvania as well as over 800 electrical wireline logs were used for this study. Information on total organic carbon (TOC) content, mineral composition, sedimentary structures and shale facies fabric as well as log data were integrated to define cyclicity. The approach required the introduction of new terms to describe important zones and surfaces. These terms include Preservation Shut-down Surface (PSS), Preservation Initiation Surface (PIS) and Maximum Preservation Surface (MPS). Accordingly, the various shale packages enclosed by these surfaces are described as Preservation Shutdown Tract (PST), Preservation Initiation Tract (PST) and Preservation Decline Tract (PDT). The results suggest that up to four cycles can be recognized from the base of the Selinsgrove/Seneca Member of the Onondaga Limestone, which underlies the Marcellus to the top of the Stafford Limestone, which overlies the Marcellus Formation. This work shows that it is possible to define cyclicity in organic matter-rich mudrocks-dominated successions without bias towards the Black Shale depositional model. URTeC 1563723

Abstract An analytical study was conducted to investigate the factors controlling hydrocarbon-generation microfracturing in organic-rich shales. The study considered both kerogen-to-bitumen and bitumen-to-oil conversions. Governing equations that describe a process of three main stages: volume expansion, pressure increase, microfracturing; were derived. Generally, Rock properties, density contrast and compressibility of the generated products are factors controlling pressure increase due to volume expansion. This study revealed that the level of organic richness, available void spaces and the existence of water are essentially key controlling factors. The role of organic richness and available void spaces become significant in the case of either lean or high-porosity shales during kerogen-to-bitumen conversion. For the role of water in volume expansion and pressure increase during bitumen-to-oil conversion, the solubility of water in bitumen gets into the governing equation. Pressure increase in the existence of water can reach as much as three times the pressure increase in the case of no water solubilized in bitumen. Comparison of kerogen aspect ratios revealed that high aspect ratios (e.g. 4:1), which indicate thin flakes of kerogen, favor horizontal microfracturing while more circular shape-like kerogens (e.g. 1:1) favor vertical microfracturing. This suggests that the geometric shape of the kerogen controls hydrocarbon-generation microfracturing once the rock tensile strength is exceeded. The effect of strength anisotropy and poroelastic behavior in microfracturing is manifested by the change of rock tensile strength with angle (with respect to bedding). The anisotropic poroelastic behavior depends on the anisotropy of the elastic moduli (Young modulus and Poisson's ratio). For kerogen aspect ratio, the difference between the principle vertical stress and the minimum horizontal stress should be four times greater than the tensile strength anisotropy in order to generate vertical microfractures. Otherwise, horizontal microfracturing is favored. These observations lead to a logical sequence for hydrocarbon-generation microfracturing: thermal maturation of organic-rich shale, conversion of kerogen to bitumen, reduction of kerogen volume and expansion of the generated bitumen volume, increase in pressure, solubilization of water in bitumen, conversion of bitumen to oil, significant expansion of the generated oil volume, significant increase in pressure, exceeding rock tensile strength and microfracturing. URTeC 1515553

Abstract The lower and upper Bakken shales in the Williston Basin are world class source rocks, sourcing reservoirs in the Bakken, upper Three Forks, and lower Lodgepole formations, which comprise the economically significant Bakken Petroleum System (BPS). Based on the Total Organic Carbon (TOC) and pyrolysis results of Bakken samples, lower and upper Bakken shales exhibit a wide range in TOC contents, laterally from 1 wt.% along shallower basin margins up to 20 wt.% in the deeper basin, and vertically with recurrent patterns in each shale section. This high variation of TOC content may result from mixed effects of the original depositional environment and progressive maturation. Based on the modified van-Krevelen diagram, the kerogen type present in Bakken shale is primarily Type II marine oil-prone kerogen, but along the shallow east flank of the basin there is Type III kerogen input. Original hydrogen index (HI) and original TOC across the basin are empirically and mathematically restored, which are averaged at ~580 mg hydrocarbon (HC)/g Carbon and ~19–20 wt.%, respectively. The pyrolysis temperature of 425ºC, production index of 0.08, and conversion fraction of 0.1~0.15, correspond to a threshold of incipient bitumen generation from early mature shales. Due to maturation and HC generation, TOC contents are diminished by about 5~8 wt.% in thermally mature areas of the Williston Basin. Early results indicate that the upper and lower Bakken shales in the central, deeper Williston Basin are organic rich, contain oil-prone kerogen, and are thermally mature and in the oil generation window. Introduction The Williston Basin is an intracratonic sedimentary basin, with the Nesson and Cedar Creek anticlines as major structures in the basin (Figure 1). The Devonian-Mississippian Bakken Formation of the Williston Basin in central North America is recently described as part of a continuous and unconventional petroleum system (Figure 2). The Bakken Formation consists of four members, in ascending order: the Pronghorn calcareous siltstone member, lower Bakken shale member, middle Bakken dolomitic siltstone and sandstone member, and upper Bakken shale member. The contact between Bakken and Three Fork formations is unconformable along the basin margin but conformable in the central part of the basin. The Bakken Formation is conformably overlain by Lodgepole Formation. The lower and upper Bakken shales are world class source rocks in the Williston Basin, sourcing reservoirs in the Bakken, upper Three Forks, and lower Lodgepole formations, which comprise the economically significant Bakken Petroleum System (BPS). 10 to 400 billion barrels of oil have been estimated to have been generated from the Bakken shales, charging both unconventional and conventional plays in the BPS. URTeC 1581243