Mission Canyon Formation Research Articles

The role of preexisting fractures and faults during multistage hydraulic fracturing in the Bakken Formation

We performed an integrated study of multistage hydraulic fracture stimulation of two parallel horizontal wells in the Bakken Formation in the Williston Basin, North Dakota. There are three distinct parts of this study: development of a geomechanical model for the study area, interpretation of multiarray downhole recordings of microseismic events, and interpretation of hydraulic fracturing data in a geomechanical context. We estimated the current stress state to be characterized by an NF/SS regime, with [Formula: see text] oriented approximately [Formula: see text]. The microseismic events were recorded in six vertical observation wells during hydraulic fracturing of parallel wells X and Z with three unusual aspects. First, rather than occurring in proximity to the stages being pressurized, many of the events occurred along the length of well Y, a parallel well located between wells X and Z that had been in production for approximately [Formula: see text] years at the time X and Z were stimulated. Second, relatively few fracturing stages were associated with an elongated cloud of events trending in the direction of [Formula: see text] as was commonly observed during hydraulic fracturing. Instead, the microseismic events in a few stages appeared to trend approximately [Formula: see text], approximately 30° from the direction of [Formula: see text]. Earthquake focal plane mechanisms confirmed slip on faults with this orientation. Finally, the microseismic events were clustered at two distinct depths: one near the depth of the well being pressurized in the Middle Bakken Formation and the other approximately [Formula: see text] above in the Mission Canyon Formation. We proposed that steeply dipping N75°E striking faults with a combination of normal and strike-slip movement were being stimulated during hydraulic fracturing and provided conduits for pore pressure to be transmitted to the overlaying formations. We tested a simple geomechanical analysis to illustrate how this occurred in the context of the stress field, pore pressure, and depletion in the vicinity of well Y.

Northwest McGregor field CO2 Huff ‘n’ Puff: A case study of the application of field monitoring and modeling techniques for CO2 prediction and accounting

Northwest McGregor field CO2 Huff ‘n’ Puff: A case study of the application of field monitoring and modeling techniques for CO2 prediction and accounting

Rietveld analysis of X‐ray powder diffraction patterns as a potential tool for the identification of impact‐deformed carbonate rocks

Abstract— Previous X‐ray powder diffraction (XRD) studies revealed that shock deformed carbonates and quartz have broader XRD patterns than those of unshocked samples. Entire XRD patterns, single peak profiles and Rietveld refined parameters of carbonate samples from the Sierra Madera impact crater, west Texas, unshocked equivalent samples from 95 miles north of the crater and the Mission Canyon Formation of southwest Montana and western Wyoming were used to evaluate the use of X‐ray powder diffraction as a potential tool for distinguishing impact deformed rocks from unshocked and tectonically deformed rocks. At Sierra Madera dolostone and limestone samples were collected from the crater rim (lower shock intensity) and the central uplift (higher shock intensity). Unshocked equivalent dolostone samples were collected from well cores drilled outside of the impact crater. Carbonate rocks of the Mission Canyon Formation were sampled along a transect across the tectonic front of the Sevier and Laramide orogenic belts.Whereas calcite subjected to significant shock intensities at the Sierra Madera impact crater can be differentiated from tectonically deformed calcite from the Mission Canyon Formation using Rietveld refined peak profiles, weakly shocked calcite from the crater rim appears to be indistinguishable from the tectonically deformed calcite. In contrast, Rietveld analysis readily distinguishes shocked Sierra Madera dolomite from unshocked equivalent dolostone samples from outside the crater and tectonically deformed Mission Canyon Formation dolomite.

Integration of geology, petrophysics, and reservoir engineering for characterization of carbonate reservoirs through Pickett plots

The concept of rock fabric has been shown to be very useful for characterization of carbonate reservoirs. This study shows that a Pickett crossplot of interparticle porosity vs. true resistivity (in some cases, apparent resistivity or true resistivity affected by a shale group) should result in a straight line for intervals with a constant rock fabric. The slope of the straight line is related to the porosity exponent m, the water saturation exponent n, and the size of the particles forming the interparticle porosity. Different slopes are obtained for different rock fabrics. The method helps to reconcile geology to fluid flow by illustrating the important link between geology, petrophysics, and reservoir engineering.Lines of constant rock fabric are displayed on a Pickett plot, together with water saturation, permeability, process speed k/, capillary-pressure curves, pore-throat apertures r35 and rp35, Kozeny's constant (Fs2), and height above the free-water table. Pattern recognition while placing all these data in a consistent form on a Pickett plot allows determination of flow units and a more rigorous characterization of carbonate reservoirs. The method is aimed at heterogeneous carbonate reservoirs, which have a limited amount of hard data.The use of this technique is illustrated with data from the Mission Canyon Formation in the Little Knife field of North Dakota, where a significant volume of oil in place is below the structural closure and updip wells penetrate microports that provide an effective seal in this stratigraphic trap.

The Integration of Capillary Pressures and Pickett Plots for Determination of Flow Units and Reservoir Containers

Summary This paper shows how to construct lines of constant capillary pressure, process speed, pore-throat aperture, and height above the free water table on a Pickett plot. The integration of these properties allows the determination of flow units and reservoir containers and illustrates the important link between geology, petro-physics, and reservoir engineering. The concept of flow (or hydraulic) units and reservoir containers has been used in the oil industry with a good deal of success during the past few years. The process or delivery speed k/ϕ can be used in many instances to define a flow unit. Correlation of flow units between wells helps to establish reservoir containers and forecast reservoir performance. We show that a Pickett crossplot of effective porosity vs. true resistivity should result in parallel straight lines for intervals with constant process speed k/ϕ. The slope of the straight lines is related to the porosity exponent m, the water-saturation exponent n, and constants in the absolute permeability equation. From the straight lines, it is possible to determine capillary pressures and pore-throat apertures directly for each flow unit at any water saturation. Pore throats at 65% water saturation compare very well with Winland r35 values. The method has not been published previously in the literature. Building lines of constant k/ϕ allows the display of complete capillary pressure curves on the Pickett plot, including regions that are and are not at irreducible water saturation. Previous empirical methods for determining the absolute permeability of a given interval assume that the water saturation is at irreducible conditions. This paper presents a technique that allows us to estimate absolute permeability even if the interval contains moveable water. The use of this technique is illustrated with previously published data from the Morrow sandstone in the Sorrento field of southeastern Colorado and carbonates from the Mission Canyon formation in the Little Knife field of North Dakota. We conclude that flow units can be determined reliably from the integration within one single log-log graph of Pickett plots, capillary pressures, pore-throat apertures, and Winland r35 values.

ABSTRACT: Facies Cyclicity and High Resolution Sequence Stratigraphy of the Tilston Beds (Mission Canyon Formation), SW Manitoba, Canada

ABSTRACT: Facies Cyclicity and High Resolution Sequence Stratigraphy of the Tilston Beds (Mission Canyon Formation), SW Manitoba, Canada

ABSTRACT: Dolomitization of The Mississippian Mission Canyon Formation, Northern Bighorn Basin, Montana And Wyoming: Petrographic And Isotopic Constraints

ABSTRACT: Dolomitization of The Mississippian Mission Canyon Formation, Northern Bighorn Basin, Montana And Wyoming: Petrographic And Isotopic Constraints

Fabric alteration and isotopic signature of carbonates in a recharge area of the Madison Aquifer, Montana, USA

The Mississippian Mission Canyon Formation (Madison Group) is a shallow-water carbonate unit that has intermittently acted as an aquifer over geologic time. Outcrops in a modern recharge area provide physical evidence of conduit flow in the form of paleocaves, bedding plane conduits, and solution channels. Principal alterations of the rock matrix are microspar neomorphism, leaching, and dedolomitization of carbonate mudstones. Petrographic and isotopic data indicate that the modern aquifer is equilibrating with ground water and over printing characteristics that may have been inherited from paleoaquifers.

Abstract: Distribution and Controls on Carbonate Reservoir Quality in the Mississippian Mission Canyon Formation, Carter Creek Field, Uinta County, Wyoming

Abstract: Distribution and Controls on Carbonate Reservoir Quality in the Mississippian Mission Canyon Formation, Carter Creek Field, Uinta County, Wyoming

Abstract: Cementation History of the Mission Canyon Formation, Montana and Wyoming 

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Integration of Geology and Reservoir Engineering to Produce Reservoir Simulation Model at Cabin Creek Field, Cedar Creek Anticline, Montana: ABSTRACT

Because of its mature stage of development, a key aspect of continued economic development of the Cedar Creek Anticline (CCA), Montana (STOOIP > 2 billion barrels with over 360 MMstb produced) is the Identification of remaining pods of high S[sub o] within the original field boundaries. Present economic conditions make it essential to select drillsites with high probabilities of success and high prognoses flow rates in these remaking high S. area. Integration of a well-constrained geologic model and reservoir simulation pinpointed remaining pods of oil in a 3-m thick, subvertically fractured, dolomitic limestone reservoir of the Carboniferous Mission Canyon Formation in the Cabin Creek Field of the CCA This resulted in a successful high-flow-rate horizontal well (initial rate >800 BOPD) whose oil production was accurately predicted by a 3-D reservoir simulation. The model has 53,750 gridblocks each of which Is 60 by 60 m. The effect of the natural-fracture network was constrained with the k[sub v]/k[sub h] (vertical to horizontal permeability ratio). The simulation covered a 40-yr. production period. Gross production was Input as a constraint; oil and water rates were matched. Adjustments to absolute permeability, aquifer volume and relative water permeability were required to obtain a match between observedmore » and simulated production rates. The model was fine tuned by matching the production of individual wells in areas with a high remaining S[sub o]. This project demonstrated that (1) interplay of geology and reservoir engineering provided a better reservoir model than could have been done individually, (2) simulation work identified horizontal drilling and recompletion candidates, with one successful horizontal well completed to date, and (3) use of the reservoir simulator for field-scale modeling In conjunction with a well-refined geologic synthesis can successfully pinpoint undeveloped reserves at CCA.« less

Regional Porosity Patterns in the Sherwood Subinterval of the Mission Canyon Formation, Southwest to North-Central North Dakota: ABSTRACT

Regional Porosity Patterns in the Sherwood Subinterval of the Mission Canyon Formation, Southwest to North-Central North Dakota: ABSTRACT

Regional Stratigraphic and Facies Relationships in the Sherwood Subinterval of the Mission Canyon Formation, Southwest to North-Central North Dakota: ABSTRACT

Regional Stratigraphic and Facies Relationships in the Sherwood Subinterval of the Mission Canyon Formation, Southwest to North-Central North Dakota: ABSTRACT

Mississippian Subaerial Exposure Surfaces within the Sherwood Subinterval, Mission Canyon Formation, Lucky Mound Field, North Dakota: ABSTRACT

Mississippian Subaerial Exposure Surfaces within the Sherwood Subinterval, Mission Canyon Formation, Lucky Mound Field, North Dakota: ABSTRACT

Alteration of early-formed dolomite during shallow to deep burial: Mississippian Mission Canyon Formation, central to southwestern Montana

Dolomite in the Mississippian Mission Canyon Formation (Osagean to middle Meramecian) of central and southwestern Montana precipitated during multiple episodes of dolomitization and/or recrystallization. The earliest generation of dolomite most likely precipitated from evaporated sea water in near-surface diagenetic environments when the Mission Canyon platform intermittently aggraded to sea level. This dolomite has relatively positive [delta][sup 18]O values ([minus]1.5% to +7.5%) and typically is nonstoichiometric and trace-element enriched. A second generation of dolomite has very negative [delta][sup 18]O values ([minus]11.2% to [minus]1.5%) and always is stoichiometric and trace-element depleted. Dolomite with [delta][sup 18]O values < [minus]6.8% is in the upper 100-180 m of the Mission Canyon Formation, beneath a regional post-Mission Canyon unconformity and karst surface that extends across the entire study area. Dolomite depleted in [sup 18]O may have (1) precipitated initially in a regional mixing zone during post-Mission Canyon subaerial exposure and karstification, (2) precipitated at elevated temperatures during later diagenesis, or (3) recrystallized from an earlier generation of dolomite during later shallow to deep burial diagenesis. Very negative [delta][sup 18]O values and low trace-element contents for the second generation of dolomite suggest that diagenetic solutions were dominated by meteoric water, whereas [delta][sup 13]C values indicate that diageneticmore » fluids were buffered by Osagean carbonate rocks. 54 refs., 10 figs.« less

Stable isotopic composition of meteoric calcites: Evidence for early mississippian climate change in the mission canyon formation, Montana

The Lower Mississippian Mission Canyon Formation of central to southwestern Montana was deposited under dominantly semiarid to arid climatic conditions during Osagean to early Meramecian times. Following deposition, a pronounced climatic shift to more humid conditions occurred during middle Meramecian times. This climatic change is indicated by extensive, post-depositional karst fabrics and in the stable isotopic composition of early, meteoric calcite cements and diagenetically altered sediments. Early meteoric calcite cement in Mission Canyon limestones is generally nonluminescent and fills intergranular and fenestral porosity. Petrographic data indicate that this cement formed during intermittent subaerial exposure of the Mission Canyon platform during Osagean times. This initial generation of meteoric calcite cement has δ 18O values from −8.1 to −2.6%. PDB. These data, and the oxygen isotopic values from nonluminescent skeletal grains and micrite in host limestone indicate that Osagean meteoric water may have had δ 18O values as low as −6.0%. SMOW. A second generation of petrographicalty similar, but isotopically distinct, calcite cement fills biomolds and porosity within solution-collapse breccias in the Mission Canyon Formation. This cement generation postdates earlier nonluminescent Osagean calcite cement and is volumetrically most abundant near the top of the Mission Canyon Formation. δ 18O values from these cements and from nonluminescent lime mudstone clasts and matrix in solution collapse breccias range from − 13.8 to − 8.2%. PDB. These data indicate that Meramecian meteoric water may have had δ 18O values as low as − 12.0%. However, a higher-temperature burial overprint on the δ 18O values of the calcite cement cannot he ruled out. The more positive δ 18O values of the Osagean calcite components probably indicate warm and arid conditions during short-term [10 4(?) yr] subaerial exposure along intraformational sequence and parasequence boundaries. The more negative δ 18O values from Meramecian calcite components and the extensive karst associated with the post-Mission Canyon unconformity may have developed because of cooler and more humid climatic conditions and possible rain-out effects during middle Meramecian times. A dramatic shift towards cooler and more humid climatic conditions may be coincident with the onset of major continental glaciation in the Early Carboniferous. The post-Mission Canyon unconformity has been attributed to a major fall in sea level that may have glacio-eustatic origins. Growth of continental glaciers during a time of global cooling would have caused migration of polar fronts further toward the paleoequator. These polar fronts in turn, would have pushed moist, mid-latitude weather systems toward the paleoequator, resulting in cooler, more humid conditions in low-latitude settings during “icehouse” times.

Sequence Stratigraphy of Mississippian Peritidal and Shallow Marine Carbonates, Mission Canyon Formation, Williston Basin, North Dakota

Sequence Stratigraphy of Mississippian Peritidal and Shallow Marine Carbonates, Mission Canyon Formation, Williston Basin, North Dakota

Exploration Opportunities in the Glenburn, Sherwood, and Rival Members of the Upper Mission Canyon Formation Along the Northeast Flank of the Williston Basin

Exploration Opportunities in the Glenburn, Sherwood, and Rival Members of the Upper Mission Canyon Formation Along the Northeast Flank of the Williston Basin

Seismic Velocities In Carbonate Rocks

Abstract Seismic velocities were measured in the laboratory vs pressure, temperature, and saturation on over 80 cores from various carbonate reservoirs in Alberta, using an ultrasonic pulse transmission method. Porosity, permeability, electrical properties, and capillary pressure were also measured in order to characterize the pore systems. All the measured data and other information are compiled into a database. The results show that both permeabilities and seismic velocities are related to the porosities of the cores, although the data are scattered. Liquid saturation (e.g. oil and water) increases the compressional velocity but has only nominal effect on the shear velocity. The magnitude of the increase in compressional velocities with liquid saturation is dependent upon the pore geometry of the rocks, reservoir pressure, as well as the distribution and properties of the saturating fluids. The velocity data are also fit to the time-average equation and the Gassmann equation. The results are usually unsatisfactory, which mean that the time-average equation used in sonic log interpretation is inadequate. For log interpretation, it might be desirable to establish a porosity-velocity relationship specific to carbonate reservoirs, instead of using the time-average equation. Furthermore, the Gassmann equation does not adequately explain the laboratory results. In most of the cores measured, the compressional velocities increase by more than 5% with oil saturation, with a subsequent decrease by over 5% when flooded with a hydrocarbon solvent. This suggests that seismic monitoring of injected gases and hydrocarbon solvent in carbonate reservoirs should be possible. Introduction Seismic properties or rocks are very important to petroleum exploration and production. In seismic exploration, velocity and density contrast between two rock layers causes reflection of seismic waves at the interface. The reflected seismic waves bring out information on the structure of the earth's crust, so that the seismic interpreter can look for potential hydrocarbon traps from the seismic profile. In the process of seismic exploration, a thorough understanding of seismic velocities in rocks plays a vital role in the success of seismic methods. In recent years, seismic methods have found other applications with success in petroleum production assessment, reservoir characterization, and enhanced oil recovery (EOR) and production monitoring. In seismic monitoring applications, the velocity contrast caused by various EOR and production processes is the physical basis of the method. Laboratory results have shown that large velocity decreases are found in heavy oil sands as temperature increases(1–5), in oil-saturated rocks when flooded with carbon dioxide (CO2(6,7) and in oil-saturated rocks when flooded with gas and hydrocarbon solvent(8,9). Furthermore, laboratory result also show large differences between the compressional velocities in gas and liquid (e.g. water or oil) saturated rocks(10). These results open the door for using seismic methods to monitor EOR and production processes. In the literature, most of the seismic velocity data were measured in sandstones and sand. Little has been published on seismic properties of carbonate rocks. Rafavich er al.(11) measured 93 Mission Canyon formation carbonate cores from four wells in the Williston basin field, North Dakota, which appears to be the only systematic study of seismic velocities in carbonates.

Hydrodynamic Trapping in Mission Canyon Formation (Mississippian) Reservoirs: Elkhorn Ranch Field, North Dakota

Hydrocarbons in Mission Canyon dolomite reservoirs in the Elkhorn Ranch field are trapped by downdip flow of formation water to the northeast. Elkhorn Ranch field is located on a north-plunging anticline with only 10 ft (3 m) of crestal closure. The Mission Canyon is a regressive, shallowing upward sequence of subtidal dolomitized mudstones and wackestones grading upward into sebkha-salina evaporites. Mission Canyon oil production is localized on the north and northeast side of the structure. Maps of porosity pinch-outs and permeability barriers defined from core data, superimposed upon the Mission Canyon structure, show that most of the oil cannot be trapped by stratigraphic facies change. Southwest-trending, updip porosity pinch-outs cross the north-plunging structural axis at an angle so low that hydrocarbons would leak out to the southwest under hydrostatic conditions. Downdip hydrodynamic flow to the northeast provides the critical trapping component. Regional maps of apparent formation water resistivity and water salinity show a region of fresher water south and southwest of the field. A regional potentiometric map constructed using Horner-plot extrapolated shut-in pressure data indicates a head gradient of about 20 ft/mi (4 m/km) to the northeast at Elkhorn Ranch field. This gradient corresponds to a calculated water-oil tilt ofmore » about 50 ft/mi (20 m/km). Observed tilt of the oil accumulation is actually about 25 ft/mi (5 m/km) to the northeast. This discrepancy might be the result of the field having not yet reached equilibrium with the invading water.« less