Viking Sandstones Research Articles

2D and 3D imaging resolution trade-offs in quantifying pore throats for prediction of permeability

Although the impact of subsurface geochemical reactions on porosity is relatively well understood, changes in permeability remain difficult to estimate. In this work, pore-network modeling was used to predict permeability based on pore- and pore-throat size distributions determined from analysis of 2D scanning electron microscopy (SEM) images of thin sections and 3D X-ray computed microtomography (CMT) data. The analyzed specimens were a Viking sandstone sample from the Alberta sedimentary basin and an experimental column of reacted Hanford sediments. For the column, a decrease in permeability due to mineral precipitation was estimated, but the permeability estimates were dependent on imaging technique and resolution. X-ray CT imaging has the advantage of reconstructing a 3D pore network while 2D SEM imaging can easily analyze sub-grain and intragranular variations in mineralogy. Pore network models informed by analyses of 2D and 3D images at comparable resolutions produced permeability estimates with relatively good agreement. Large discrepancies in predicted permeabilities resulted from small variations in image resolution. Images with resolutions 0.4 to 4μm predicted permeabilities differing by orders of magnitude. While lower-resolution scans can analyze larger specimens, small pore throats may be missed due to resolution limitations, which in turn overestimates permeability in a pore-network model in which pore-to-pore conductances are statistically assigned. Conversely, high-resolution scans are capable of capturing small pore throats, but if they are not actually flow-conducting predicted permeabilities will be below expected values. In addition, permeability is underestimated due to misinterpreting surface-roughness features as small pore throats. Comparison of permeability predictions with expected and measured permeability values showed that the largest discrepancies resulted from the highest resolution images and the best predictions of permeability will result from images between 2 and 4μm resolution. To reduce permeability underestimation from analyses of high-resolution images, a resolution threshold between 3 and 15μm was found to be effective, but it is not known whether this range is applicable beyond the samples studied here.

Accessibilities of reactive minerals in consolidated sedimentary rock: An imaging study of three sandstones

Widespread implementation of geological storage of CO 2 requires an understanding of dissolution reactions with formation minerals. This will be aided by reactive transport modeling, which relies on accurate estimates of the accessible surface areas of reactive minerals in consolidated sedimentary rocks. For three Viking sandstones (Alberta sedimentary basin, Canada), we have employed backscattered electron microscopy and energy dispersive X-ray spectroscopy to examine mineral content and to statistically characterize mineral contact with pore space. Porosities range from 20% in a lightly-cemented sandstone with grains on the order of 100 μm, to 8% in a highly-cemented shaly sandstone with a mix of primary pore space and fractures, to 7% in a lightly-cemented conglomerate sandstone with grain sizes between 500 μm and 1 mm. In all three specimens, kaolinite is the primary authigenic clay mineral cementing quartz grains. It accounts for only 5% to 31% of mineral content, but 65% to 86% of pore-mineral contact boundaries. The sandstone specimen has 6% minerals in the “reactive” category, which in this study includes minerals other than kaolinite and quartz, such as K-feldspar, apatite and pyrite. For this specimen, only one third of the reactive minerals are accessible to pore fluids due to clay-mineral grain coatings. For the shaly sandstone, only one fifth of its 5% reactive minerals are accessible to pore fluids due to regions of cementation of fine detrital matrix. Thus, if a mineral volume fraction is used in reactive transport modeling as a proportional measure of accessible surface area in consolidated sandstones, the reaction rates are likely to be overestimated by three to five times. The conglomerate sandstone has only 1% of its mineral matter in this category, and these are often found as inclusions rather than grains.

The Effect of Reservoir Heterogeneity On Predicted Waterflood Performance In the Dodsland Field

Abstract Predicted waterflood performance in the Dodsland Viking field has not occurred. Previous study identified that the effects of hydraulic fractures must be taken into account in order to predict performance. The revised predictions are still somewhat optimistic when compared to actual production. The previous work has been extended to account for reservoir layering. Core data has been used to provide a quantitative analysis. Due to extreme permeability contrasts, it is difficult to simulate large ranges in formation permeability as separate layers. Hearn type relative permeability curves were therefore used. With high reservoir heterogeneity, waterflood response may consist only of a levelling of production. This prediction is consistent with actual well performance observed. The methodology used and its limitations are discussed. Additionally, the effects of well spacing and fracture extension are presented. This work has important economic implications for existing and planned waterfloods:Wells which are producing below their economic limit, awaiting predicted waterflood response, can be shut-in. This was used to implement substantial reductions in operating costs.More realistic estimates of waterflood response in highly stratified reservoirs can be made by using core data and Dykstra-Parson ratios prior to implementation. Introduction Outline This paper summarizes a study originally made for an individual unit. Although the results are more broadly applicable, the outline fo(Jows the historical development, under the following headings:Geological DescriptionProduction PerformanceModel ConstructionReservoir ModellingConclusions This work is an extension of work done previously by Carlson and Andrew(1). Although this paper has been written on a standalone basis, further background data may be found in the previous paper. Background The Dodsland field located in south-west Saskatchewan was first discovered in 1953. The location of the field is shown in Figure 1. Light oil (36 ° API) production is obtained from the Cretaceous aged Viking sandstone. Delineation of the field occurred rapidly during the 1950's. Unitization and waterflooding followed in the mid 1960's. A resurgence in development occurred in the la[e 1970's and early (980's due to high oil prices. Development in the mid 1980's was also fuelled by attractive government incentives. Geological Description Lithology The Viking consists of an interbedded shale and sandstone. The sandstone is a poor quality reservoir rock; however, i[s shallow drilling depth and large area have permitted extensive development. The lithology has been described in detail by Tooth et al.(2). The sandstone portions typically consist of sublitharenates which locally grade into siltstones of similar composition. Porosity is intergranular with significant amounts of micro-porosity associated with clay mineral assemblages. Cementing by silica, siderite, pyrite and kaolinite is poor. The more productive areas of the reservoir are comprised of 4.6 to 7.6 m (15 to 25 ft.) thick sandstones with discrete shaly partings. In the less productive areas. The shale partings are dense and the pay consists of thin lenses of sandstone. This layering does not show directly on well logs since it is so fine.

THE VIKING (ALBIAN) RESERVOIR SANDSTONES OF CENTRAL AND SOUTH‐CENTRAL ALBERTA, CANADA

Bentonite chronostratigraphy indicates that deposition of the Viking Formation in central and south‐central Alberta and SW Saskatchewan occurred within three chrono‐intervals, informally designated Basal, Lower and Upper. Sandstones of the Basal and Lower Viking times were deposited offshore, while most Upper Viking sands formed along the strandline. In general, these Viking sands trend NW‐SE, are multiple, parallel, discrete units surrounded by wales, and are of varying thicknesses.The shoreline sands, which evolved slightly earlier than Basal Viking time, prograded NE towards the offshore for a maximum distance of about 250 kms, in places overlying the offshore sands. The offshore Basal Viking sands, characteristically thin, were deposited around Hamilton Lake, Provost, and up to Viking Kinsella in Alberta, as well as the Dodsland — Hoosier‐Smiley areas of SW Saskatchewan. The development of the Lower Viking sandbodies occurred slightly later, around the Sullivain, Ewing Lake, Joffre and Joarcam areas, SW and west of the basal sands. These offshore sand units migrated imbricatedly shorewards (SW), in opposition to the sense of progradation of the shoreline units. This SW‐direction of offshore sandridge migration is consistent with their NE flanks being relatively thinner, coarser and cleaner, suggesting NE‐SW flow currents along the NE flanks of ridges, and explains why most hydrocarbon reserves occur on the NE flanks of some of the ridges.The opposed sense of Viking sandstone migration resulted in the development of a thick mudstone interval between the strandline and offshore sandbodies, resulting in the development of a topographic sediment gradient that slopes NE. This pattern of Viking deposition explains the regional NE‐thinning pattern of the Viking Formation in Alberta, rather than it being due solely to a regressive shoreline, as previously thought.In general, Viking sandstone deposition appears to have ceased earlier in the NW than SE, suggesting that the SW source area (in the Nelson Batholith region) persisted longer than the western source area (coast Range area, west of Jasper). Missing, thin stratigraphic sections at the top of the Joli Fou, common in places in the area of the Basal sand deposition, suggest that much of the basal sediments are products of sea‐floor scouring by genetically‐related currents, rather than resulting from an unconformity, as thought by some earlier workers.

Fracturing With Crosslinked Gelled Methanol: A New Approach To Well Stimulation

Abstract Recent development of a water-free fracturing fluid has improved stimulation successes in several Alberta formations. Methanol has been used for many years to reduce formation damage caused by swelling clays and capillary blockage resulting from high-fluid surface tension. This paper discusses the development and field application of the gelling and crosslinking of commercially available methanol. The study also details the rheological characteristic of the system under dynamic conditions. The relative effects of both intensity and duration of shear hat is applied during the preparation of the crosslinked gelled methanol system are presented. Several factors that are inherent in the evaluation of a fracturing luid for field application will be discussed. These includeproppant transport capability, fluid leak-off coefficients, compatibility with carbon dioxide and safety in handling a potentially volatile fluid. Data on the zones treated as well as post-frac production results are included. Introduction Greater emphasis today is being placed on well stimulation fluids that can be used to increase production from water sensitive reservoirs. Formations with low permeability, high clay content, or low bottomhole pressure usually experience poor fluid recovery after fracturing with conventional fracturing gels. This poor post-frac performance may be attributed to permeability damage caused by the swelling of clay particles or by the migration of particles and fines(1). Slow clean-up of water in this type of formation may also be caused by gas and water relative permeability effects or by the high capillary pressure in low-permeability rocks(2). Formations containing gas reservoirs with relatively large quantities of migrating-type clays (kaolinite and mica/illite) are common throughout Alberta. Core samples from the Basal Quartz formation have been found to contain more than 20% aolinite on framework grains and in pore throats. Other Alberta gas-producing formations, such as the Viking Sandstone can contain expandable mixed-layer clay, usually illite/smectite or the. highly expandable smectite mineral. Still others contain large amounts of both the migrating type clay and the expanding type clay. An example is the Cardium formation. Methanol, with varying degrees of water and energizing fluids has been used in the past with some success to treat these problems formations. Papers documenting the successful use of methanol/water and CO2 methanol/water-based fracturing fluids have been presented. These include "Experience with CO2 Laden Fracturing Fluid for Stimulating Water-Sensitive Formations" and "The Use of Alcohol-Water Mixtures in Fracture Stimulation of Gas Wells". Recent product and chemical developments enable the use of commercial grade methanol for preparing either a medium viscosity linear gel or a high-viscosity crosslinked fluid for fracturing. With proper knowledge about the rheological properties, the proppant transport capabilities and the fluid loss control properties, a system prepared from only methanol or methanol/ CO2 can be selected to stimulate typically sensitive formations and provide improved clean-up performance. Background The application of methanol in stimulating hydrocarbon reservoirs has been the central issue of technical discussions over the years. Its virtues in fracture stimulation have been well documented and indicate that a pure methanol fracturing fluid would have many benefits in achieving successful production fromvarious reservoirs that are sensitive to other stimulation and/or complet

Foraminiferal zonation of the Viking interval in the Hasler Shale (Albian), northeastern British Columbia

A dominantly arenaceous foraminiferal fauna of over 33 genera and 65 species was recovered from silty shales in the mid-portion of the Hasler Formation in the upper Albian part of the Fort St. John Group. The assemblages lie stratigraphically below occurrences of Neogastroplites and below the Miliammina manitobensis Zone. The foraminifera come from above the occurrence of Haplophragmoides gigas gigas, although assignment of the beds is to the upper part of the H. gigas Zone.The upper part of the Haplophragmoides gigas Zone may be divided into several subzones above the H. gigas gigas Sub-zone in ascending order, viz., H. gigas ssp A Subzone, Reophax tundraensis Subzone, Trochammina depressa Subzone, Trochammina umiatensis Subzone, and Reophax troyeri Subzone.The assemblages have close affinities with the faunas of both the overlying and underlying shales, and are an expression of a late shallowing–deepening cycle within the Skull Creek – Joli Fou seaway. They were penecontemporaneous with Viking Sandstone deposition in Alberta. The assemblages are interpreted as mid-neritic to shallow neritic from slightly acidic waters. Only 4 of 150 samples collected carried calcareous components. Diagnostic megafauna are lacking.The microfaunas include the following genera: Bathysiphon, Hyperammina, Kechenotiske, Thuramminoides, Psammosphaera, Saccammina, Reophax, Scherochorella, Hippocrepina, Glomospira, Glomospirella, Ammodiscus, Miliammina, Psamminopelta, Haplophragmoides, Trochamminoides, Ammomarginulina, Ammobaculites, Haplophragmium, Ammobaculoides, Trochammina, Textulariopsis, Pseudobolivina, Verneuilinoides, Verneuilina, Uvigerinammina, Gaudryina, Gravellina, Eggerella, Lenticulina, Marginulina, Lagena, Nodosaria.

Oxygen-isotope studies of clastic diagenesis in the Lower Cretaceous Viking Formation, Alberta: implications for the role of meteoric water

Summary The oxygen-isotope compositions and paragenetic sequence of diagenetic minerals from the Lower Cretaceous Viking sandstone and conglomerate from south-central Alberta, Canada have been used to identify changes in porewater composition during diagenesis and to relate these changes to major geological events within the western Canada sedimentary basin. Large-scale influx of meteoric water has played an important role in diagenesis of this unit, especially following uplift of the basin in early Eocene time. Diagenetic phases include early kaolinite ( δ 18 O SMOW = + 24.9 to +28.2 ‰), siderite ( δ 18 O SMOW = + 22.0 to + 23.9 ‰; δ 13 C PDB = −6.3 to −1.3 ‰), calcite ( δ 18 O SMOW = + 26.0 ‰; δ 13 C PDB = −0.4 ‰) and chlorite ( δ 18 O SMOW = + 10.7 − + 13.4 ‰), followed in order by dolomite ( δ 18 O SMOW = + 19.3 − + 22.1 ‰; δ 13 C PDB = −5.9 to −2.6 ‰), calcite ( δ 18 O SMOW = + 13.9 − + 15.9 ‰; δ 13 C PDB = −8.4 to −6.1 ‰), ankerite ( δ 18 O SMOW = + 16.3 − + 17.9 ‰; δ 13 C PDB = −12.4 to −3.5 ‰), kaolin group minerals ( δ 18 O SMOW = + 12.0 − + 15.7 ‰), and illite ( δ 18 O SMOW = + 14.2 − + 15.7 ‰) and illite/smectite ( δ 18 O SMOW = + 13.8 − + 16.5 ‰). Quartz overgrowths ( δ 18 O SMOW = + 16.2 − + 27.4 ‰) began crystallizing relatively early during burial diagenesis and continued to form at least up to the onset of late diagenetic formation of clay minerals. The interpretation of these results is that shallow diagenesis, early in the burial history (glauconite, pyrite, calcite, chlorite), occurred largely in the presence of seawater-derived fluids, although a freshwater influence is indicated where siderite and(or) early kaolinite cements are abundant. As compaction and burial diagenesis proceeded (diagenetic chlorite, quartz overgrowths, dolomite), the porewaters became enriched in 18 O due to water/rock interaction. Burial diagenesis was terminated in the early Eocene by uplift related to the major Laramide Orogeny. Recharge of the basin by low 18 O meteoric water occurred at this time. The meteoric water then became involved in the formation of diagenetic quartz, calcite and ankerite (and the dissolution and albitization of feldspar) at or near maximum burial temperatures, and in the crystallization at lower temperatures of kaolin group minerals, illite and illite/smectite as the post-Eocene erosion progressed.

Design Considerations For Carbon Dioxide Injection Facilities

Abstract The first miscible carbon dioxide enhanced oil recovery project in Canada began in 1984 with the injection of CO2 into the Joffre Viking Tertiary Oil Unit by Vikor Resources Ltd. and the Alberta Oil Sands Technology and Research Authority (AOSTRA). Carbon dioxide injection facilities capable of injecting gaseous CO2 from a nearby petrochemical complex and liquid CO2 trucked to the site are discussed. The paper examines some process, instrumentation, material and operating considerations incorporated into the design of the project's carbon dioxide compression, dehydration, injection well and measurement equipment. Introduction Since the early 1970s considerable effort has been expended by industry in the research and field testing of miscible displacement of oil using CO2. In the United States, the number of CO2 miscible projects have blossomed to over thirty in the past two years. In the United States carbon dioxide miscible flooding is expected to contribute about 50 000 m3 I d of tertiary oil by 1995, and should develop dose to 500 million m3 of oil reserves. Although the potential a f miscible CO2 flooding is somewhat more limited in Canada than in the United States due to the lack of large natural occuring CO2 deposits, miscible CO2 flooding is still expected to contribute significantly to Canada's future oil reserves. A recent study by the National Energy Board (NEB) showed carbon dioxide miscible flooding to have an economic potential for recovering 50 million m3 of oil reserves, about 15% of Canada's anticipated 320 million m3 tertiary oil reserves. The first field testing of miscible CO2 technology in Canada is currently being operated by Vikor Resources Ltd. on behalf of the Alberta Oil Sands Technology and Research Authority (AOSTRA) and the Joffre Viking Tertiary Oil Unit in the Joffre Viking sandstone, approximately IS km northeast of Red Deer (Fig. 1). The project is located in an area of the reservoir which had been produced to its economic limit under water flood in the 1960s. The project consists of four water pre-pressure wells flanking two adjacent inverted five-spot CO2 injection patterns which are produced under a water alternating gas (WAG) process (Figs. 2 and 3). The project has been injecting CO2 since January 1984. Response to the CO2 injection has been observed, indicating the commercial potential of the process. This paper will deal with some of the process and mechanical design considerations of the CO2 injection system in Joffre; identifying potential problems specific to CO2 and commenting on recommendations to economically ameliorate each problem area. Injection System The CO2 injection system is shown schematically in Figure 4, It includes gaseous CO2 from Alberta Gas Ethylene Company (AGEC) and a liquid CO2 system located at the Central Battery. These two CO2 sources are comminglid at the Vikor Central Battery, and then distributed to the WAG injection wells. Separate water and CO2 injection systems to each WAG injection well are provided as corrosion in gaseous CO2 streams depends mainly on the presence of water.

Retrogradational Shelf Sedimentation: Viking Sandstone (Lower Cretaceous), Central Alberta: ABSTRACT

The Viking Sandstone in the Joffre-Joarcam area of central Alberta consists of a series of overlapping sediment sheets becoming progressively younger westward toward the paleoshoreline. During the regression at the beginning of Viking deposition, streams meandered across the former shelf surface depositing sand in deltas (today's irregular-shaped reservoirs). An ensuing transgression, punctuated by minor regressions, reworked shoreline sediment deposited during the regressions into linear shelf sand bodies (today's linear reservoirs west of the irregular-shaped reservoirs). During the transgression, the retrogradational nature of the sediment sheets, which contain the sand bodies, was formed. Well-log cross sections show that the Viking thickens westward, pinches out eastward, and that each sediment sheet contains several northwest-trending shoestring sandstone bodies. Cores of the sandstone bodies and their underlying beds exhibit a coarsening-upward succession of: (1) silty marine shale; (2) intercalated silty shale and rippled sand (locally a structureless bioturbated clayey sand); and (3) glauconitic cross-bedded sandstone. A polymictic pebble conglomerate occurs randomly within this sequence. Submerged deposition on a shelf tens of miles from the paleoshoreline is documented by: (1) marine shale enclosing the Viking; (2) no consistent landward-seaward facies changes; (3) abundant glauconite; (4) an End_Page 674------------------------------ offshore trace fossil assemblage; (5) coarsening-upward sequence of lithologies; and (6) position with respect to the strandline facies. Scarce evidence, such as coal partings and plant fragments, from irregular-shaped fields seems to be inconsistent with deposition offshore. All evidence, however, along with the shingling of the sediment sheets can be explained by retrogradational shelf sedimentation. Modern sediments of the New Jersey shelf are analogous. End_of_Article - Last_Page 675------------

Depth-porosity relationships in the Viking and Cardium formations of central Alberta

ABSTRACT The Viking and Cardium Formations occur at relatively shallow depths in central Alberta, and at progressively greater depths toward the Alberta foothills. Because of the abundance of core and reservoir data, certainty of correlation, and undeformed state, these formations provide ideal case studies for establishing depth-porosity relationships in sandstones. Seventeen cores of the Viking, ranging from depths of 640 m to 2640 m, and ten cores of the Cardium, ranging from 1220 m to 2745 m, were used. Studies of other formations have indicated that, in general, porosity decreases with depth in a linear fashion. The porosity-depth relationship of the Viking is essentially linear and may be termed normal. The Cardium Formation, on the other hand, shows no distinct trend with depth and is therefore considered to be abnormal. The scanning-electron microscope has been used to document diagenetic changes with depth, and to attempt to understand the differences between the two formations. Porosity values for the Viking Formation range from 19 to 36 per cent over a depth interval from 640 m to 915 m as a result of variations in concentrations of such components as authigenic clays, detrital clays and pyrite. Below 915 m, the porosity values gradually decrease to 6 per cent at a depth of 2640 m. The general reduction of porosity with increasing depth of burial in the Viking sandstones is due primarily to mechanical compaction, chemical compaction and quartz-overgrowth development. In contrast to the Viking Formation, porosity values of 20 per cent can be found in the Cardium sandstones at depths of over 2700 m. However, variations do exist in porosity values at similar depths because of differing concentrations of detrital clays, authigenic clays, calcite and siderite. In the Cardium sandstones, there is some porosity reduction with increased burial depth due to mechanical compaction, chemical compaction and quartz overgrowth development. However, the migration of hydrocarbons into the Cardium sandstones essentially terminated diagenesis and with further burial overpressuring was developed.

Depositional History of the Viking Formation, Suffield Area, Alberta, Canada

ABSTRACT A subsurface study of the Viking Formation in southeastern Alberta, between Townships 19 and 26 and Ranges 1 and 16 west of the 4th meridian, was undertaken to determine its depositional environment and depositional history. This area is just north of the transition from the Bow Island Formation of the southern Plains to the Viking Formation of the central Plains, and is in the region of multiple sand development in the Viking Formation. Fourteen Viking cored wells and 250 electric logs distributed throughout the area were studied in detail. The cores examined show vertical successions of structures and textures similar to those of barrier island sands previously described by other authors, and generally allow delineation of lower, middle and upper foreshore zones. There is a lack of recognizable lagoon or eolian facies. Little interference with circulation of normal marine water may be attributable to the distance of the bars from shore, but would also depend on extent and permanence of emergence, which is still speculative. The self-potential curves of the Viking Sandstone are of the typical funnel shape to which Krueger (1968) ascribed barrier bar deposition. Core and electric log examination shows the Viking Formation to consist of two main sands, here called the Upper and Lower Viking Sandstones. A diagnostic 6 to 12 in (15 to 30 cm) bentonite bed within the Viking Formation is correlatable on electric logs as a time datum throughout the study area. This bentonite, in conjunction with several thinner nearby bentonites, gives an average potassium-argon radiometric age of about 100 million years. The thickness of Lloydminster shale between the bentonite datum and the overlying Fish Scales Sandstone increases eastward. Foraminifers studied from samples a few feet above the Viking Formation in the Lloydminster Shale revealed the biostratigraphic position of the Viking Formation to be just below the Miliammina manitobensis Zone. Cross sections utilizing the bentonite as a time datum show the depositional development of the Viking Sandstone. The Lower Viking Sand was deposited as a northwest-trending barrier bar with greatest thickness in the centre of the study area. The Upper Viking sand, deposited above the bentonite time marker, represents an eastward-prograding barrier bar that has its maximum development in the northeast corner of the map area, with a north-northwest trend.

Formation Pressure Patterns in Cretaceous Viking Formation, Alberta: ABSTRACT

Regional potentiometric maps of the Lower Cretaceous Viking Formation in central Alberta indicate a low-pressure area or sink centered on the Joffre-Bentley-Gilby trend of oil fields, with formation waters in central Alberta flowing into the trend. According to integrated geologic and pressure studies, the sink actually consists of 6 separate, nearly static, pressure systems controlled by the environmental facies and subsequent structural deformation. The Viking reservoirs are interpreted to be lenticular sandstone bodies deposited as en echelon offshore bars with a NW-SE trend. Postdepositional uplift and subsequent erosion have exposed the Viking sandstones at their lateral extremities; in places, these extremities are covered by a thin veneer of permeable glacial deposits. Five of the 6 pressure systems in the Viking appear to be controlled by the distribution of these bars and by the elevations of outcrops. The sixth system is characterized by pressures 1,200 psi below hydrostatic pressure End_Page 850------------------------------ and by as much as 1,900 psi below the outcrop-controlled systems. This system is interpreted to be a sandstone lens completely enclosed in shale; its pressures were developed by geo-osmosis, as indicated by facies relations, shale analyses, and salinity maps. The osmotic cell in this system consists of the low-salinity Viking sandstone and the deeper, high-salinity, Mannville sandstone and shale; the semipermeable membrane of the system is the intervening Joli Fou shale. Because the Viking sandstone system is isolated from the outcrop by shale and shaly rocks of very low permeability, the osmotic process produced a marked pressure anomaly. End_of_Article - Last_Page 851------------

Increasing Injectivity of Shaly Sands With Chemicals

CHAKRAVORTY, S.K., HUDSON'S BAY OIL and GAS CO., LTD., CALGARY, ALTA. GATEMAN, J.C., HUDSON'S BAY OIL and GAS CO., LTD., CALGARY, ALTA. MEMBERS AIME BOHOR, B.F., CONTINENTAL OIL CO., PONCA CITY, OKLA. KNUTSON, C.F., CONTINENTAL OIL CO., PONCA CITY, OKLA. Abstract The Viking sandstone reservoir, Coleville-Smiley field, Saskatchewan, Canada, is very shaly and water sensitive. The proven sources of injection water in the area are relatively fresh and in laboratory tests quickly plug tile Viking cores. After screening a large number of chemicals in the laboratory, a two-stage treatment was developed that maximized water permeabilities in core plugs. The purpose of the treatment was to restrict or inhibit clay swelling, prevent bacterial growth and increase injectivity. No one chemical was found that could do all these jobs well, so a three-component system was used: potassium chloride, polyoxyethylene triethylenediamine and an imidazoline. The optimum laboratory technique was to use a spearhead containing a high concentration of the treating chemicals followed by continuous treatment of the injection water with these material. Introduction The Eureka Viking sand pool is located in Southeastern Saskatchewan, about 200 miles northwest of Regina, 50 miles east of the Alberta-Saskatchewan border, and 200 miles north of the International Boundary (Fig. 1). The pool is located on the western end of the Dodsland field and is approximately 15 miles east of the Smiley-Dewar Viking sand pool. These two pools are within the Coleville-Smiley field boundaries as defined by the Saskatchewan Dept. of Mineral Resources. The producing formation of these pools is the Viking sandstone found at a depth of approximately 2,300 ft. The discussion presented in this paper pertains only to the Viking formation. Production was first established from the Viking sandstone in this area in Sept., 1953, with the discovery of the Smiley-Dewar pool. Discovery of the Eureka pool followed in 1954 and production was established for the Dodsland field in 1958. These fields presently contain approximately 650 wells capable of production from the Viking sandstone. The Viking sand is continuous throughout this area and the oil is found in the lows or valleys of the structure. Gas caps are located between the Eureka and Smiley-Dewar pools and along the northern edge of the Dodsland field. The name and location of the well selected for the injectivity test is HB Coleville 4-26-31-23 (lsd 4-26-3 1-23 W3M) in the Eureka Viking sand pool (Fig. 2). Other pilot water injection wells are located in lsds 11-6-31-22 W3M, and 12-7-31-20 W3M in the Dodsland field, lsd 9-4-31-25 W3M, and a four-well five-spot pilot injection on section 17-31-25 W3M in the Smiley-Dewar pool. Geology and Reservoir Characteristics The Viking member of the Colorado formation is of lower Cretaceous age. It consists of gray, silty shale beds and thin beds of chert pebbles. The lower 30 ft of the Viking member, consisting of medium-grained shaly sand, is known as the Viking sandstone. Structurally, the Viking member reflects the Paleozoic erosional surface by its highs and lows. JPT P. 1107ˆ

Geometry of Oil and Gas Accumulations Associated with Edmonton Reef Chain, Central Alberta: ABSTRACT

The absence of large-scale tectonic disturbances along the eastern flank of the Alberta syncline has made the search for structurally entrapped oil and gas deposits rather minor in comparison with the stratigraphically entrapped deposits. Closed structures occur, but the controlling factors for the closed anomalies lie in draping. Draping is over reef buildups, residual topography on surfaces of unconformity, and structural noses along ancient tectonic trends. Oil and gas fields along the Edmonton reef chain provide examples of many complex stratigraphic relations which in turn control the entrapment of hydrocarbons. The principal trap along the trend is the carbonate buildup of the Devonian reef entirely enclosed by shale. The geometry of the oil and gas accumulations in the reefs simulates the normal fluid segregations found in simple anticlinal traps. Differential compaction of overlying sediments above the reef massifs causes draping in the overlying sediments and supratenuous anticlines are formed somewhat symmetrically with the reef body. Such features enable seismic exploration to delineate the reef trends, even though seismic records give poor reflections from the reef massifs themselves. Subreef structural relations are unknown at resent because of lack of deeper drilling. End_Page 1098------------------------------ The structural closures in the sediments above the reefs account for another type of trap for oil and gas. The Devonian Nisku and Wabamun carbonates, the Cretaceous Basal Quartz and Viking sandstones, and in several places the Cretaceous Cardium sandstone contain oil and gas accumulations with geometry of fluid segregations similar to that found in anticlinal closures. It must be pointed out, however, that in many places, porosity-permeability conditions in these reservoirs modify the geometry of the fluid accumulations to a great degree. A third type of trap results from erratic porosity development related to the effect of buried highs on subsequent sedimentation. In several places improved porosity conditions in the Devonian Nisku formation account for the extension of oil accumulation some distance beyond the structural closures above the reef massifs. The development of thicker, more porous sands can be found in the Cretaceous Basal Quartz above the inter-reef channels. Some old topographic depressions in the unconformity surface between the Paleozoics and Cretaceous are filled with porous sand lenses in the Basal Quartz sequence. A fourth type of trap is found in the truncated edge of several Mississippian units. Accumulations of oil and gas are found in porous Rundle carbonates as their regional updip termination crosses the Edmonton reef chain. End_of_Article - Last_Page 1099------------