Lower Cretaceous Sands Research Articles

Regional Tectonic Influence on Early Cretaceous Depositional Patterns in Powder River Basin, Wyoming and Montana: ABSTRACT

Integration of gravity, magnetic, seismic, and subsurface data from the Powder River basin indicates left-lateral wrenching caused principal and secondary shear compression to develop along northwest and east trends, respectively. This well-documented strain fabric caused by Laramide events has affected basin morphology and depositional patterns within the basin since the Early Cretaceous. Regional lineaments mapped at the surface have vertical displacements of tens of feet. These slightly displaced features can be correlated with wrench-related synthetic and antithetic fractures that display miles of subsurface lateral displacement. Results of detailed integrated forward modeling indicate these fractured zones had a significant effect on the distribution of Lower Cretaceous reservoir sands. Case histories from Buck Draw (Dakota Formation) and Bell Creek (Muddy Sandstone) fields illustrate how the consideration of basement tectonic influence is important to the proper evaluation of exploration leads. Proper use of all available data is essential to the reduction of exploratory risk and can aid in planning offset locations.

Petrography of the quartz sand deposits of the Lower Cretaceous of Bornholm, Denmark

The quartz sand of the Lower Cretaceous Robbedale Formation and lowermost part of the Jydegard Formation in the Arnager-Sose fault block of Bornholm has been investigated with respect to mineralogy, grain-size, grain rounding and grain shape. Analyses of both light and heavy minerals have been carried out for 18 samples from different localities and facies. The purpose of the investigation was to try to recognize the possible types of source rocks and provenance areas. The Precambrian basement rocks of Bornholm are not the main sources of the sand, especially not the heavy minerals, but parts of the sand may have originated from the basement. The Palaeozoic sandstones and siltstones have delivered only a small amount of material. Parts of the older Mesozoic sediments of the Bornholm Group and Homandshald Member may have been redeposited in the Lower Cretaceous as they contain the same kinds of heavy minerals as the Robbedale and Jydegard Formations, although in differing amounts. It seems very possible, however, that most of the Mesozoic sediments of Bornholm have had a source area outside Bornholm, and this source area has been nearly the same during the whole span of time. The Fenno-Scandian Shield seems to be the most obvious provenance area, but eastern and southern areas are possibilities too. It is concluded that most of the Lower Cretaceous sands are first deposition cycle sediments of both local and distant origin combined with minor amounts of polycyclic sediments of mainly local origin.

Deepest Production in Rocky Mountain Province: Madden Anticline, Fremont County, Wyoming: ABSTRACT

The Monsanto Oil Company 1-5 Bighorn well was drilled at a crestal location on the 6-mi (9.6-km) wide by 20-mi (32.2-km) long Madden anticline. It penetrated all the previously undrilled pre-Cody rocks on the structure before reaching a total depth of 24,877 ft (7,582 m), or 64 ft (20 m) into precambrian granitic rocks, where the bottom-hole temperature was recorded at 425/sup 0/F (218/sup 0/C). The well was completed August 1985 through perforations from 23,758 ft (7285 m) in the lower part of the Mississippian Madison Formation. Gas flowed at 20 MMCFD (566,000 m/sup 3//d) with a flowing tubing pressure of 5800 psi (40 MPa) and a shut-in tubing pressure of 6700 psi (46 MPa). The porosity logs indicated 70 net ft (21.3 m) of porosity, with an average porosity of 8% and a maximum of 14%. The gas composition is 74% methane, 14% CO/sub 2/, 10% H/sub 2/S, and 2% miscellaneous inerts. The productive interval in this well deepened the Rocky Mountain province depth-of-production record by 3400 ft (1034 m). Mechanical logs, gas shows, and drilling parameters indicated additional potentially commercial accumulations of gas in the Upper Cretaceous Frontier sands, the Lower Cretaceous Muddy and Cloverly sands, the Triassicmore » Crow Mountain Sandstone, the Permian Park City Formation, and the Pennsylvanian Tensleep Sandstone. The Frontier through Crow Mountain interval was significantly overpressured and required 17 lb/gal 92037 kg/m/sup 3/) of drilling fluid to maintain balance while drilling. Pressure regressed to a normal gradient near the top of the Paleozoic rocks at approximately 22,700 ft (6919 m). As many as 20 additional wells may be needed to develop the previously untested pre-Cody reservoirs on the Madden anticline.« less

Retlaw Upper Mannville 'V' Pool Unit Experimental Carbon Dioxide Flood

Introduction In November 1983, Westgrowth Petroleums Ltd. and partners initiated Canada's first carbon dioxide flood in the Retlaw Upper Mannville ‘V’ Pool, 80 miles southeast of Calgary. The flood is classified as an experimental project and is designed to test immiscible CO2 flooding of a 23 º API crude in a Glauconite sand. The CO2 project is the culmination of over two years of effort which included technical studies and research work, obtaining regulatory approvals, unitization of the project area and construction of the CO2 injection facilities. Westgrowth is operator and major owner. There are 11 co-owners. Discussion The Retlaw Upper Mannville ‘V’ Pool was discovered in 1976 by the drilling of the well 8-28-12-18 W4M and has since been developed to the south and east. Thirty-three wells have been completed on 32 ha (80 acres) spacing. The reservoir is a lower Cretaceous Glauconite sand, which is thought to be a reworked splay sand that developed from nearby fluvial channels. The pool is a stratigraphic trap that is bound by shale or sand sequences of reduced quality. There is neither free water nor oil-water contact associated with the pool, which is at an average depth of 1067 m (3,500 ft). The reservoir temperature is 35.5 ºC (96 ºF) and the original pressure was 11,373 Kpa (1,650 psi). Several small gas caps exist in the southern part of the pool. The pool has an average pay thickness of 8 feet, porosity of 18% and 50 md permeability. The original solution gas-oil ratio is 62 m3/m3 (350 SCF/bbl) and the 22 to 24 degree API gravity oil has a reservoir viscosity of 8 to 10 cp. The initial production rates for the wells varied from 2.4 to over 32.0 m3/d (15 to 200 BOPD). The concept of a CO2 flood developed from the idea of pressure maintaining the reservoir with the CO2 rich tail gas from the nearby Turin Gas Plant, 3 miles from the pool. Most of the gas wells producing into that gas plant have a higher than normal natural content of CO2. The need for a pressure maintenance scheme was apparent from quickly rising gas-oil ratios (and penalties) soon after the wells were placed on production. Waterflood was rejected because it was determined in lab studies that the hydrophillic clays in the glauconite sand swell on contact with fresh water. There wasn't enough saline water produced from other pools nearby that would be cheaply available. The inherent difficulties in waterflooding a viscous oil which had a developed free gas saturation along with the potential upside benefits of CO, flooding clinched the final decision. A number of technical studies and core floods were conducted to establish the incremental benefits of CO2, flooding. Applications were made to the ERCB and AENR to seek approval. The CO2, is expected to work well because it has a high density at the low reservoir temperature. In addition to providing pressure maintenance, the CO2 increases the recovery by swelling the oil, reducing the viscosity and by extraction.

Quantitative Evaluation of Lower Cretaceous Mannville Group as Source Rock for Alberta's Oil Sands

The Western Canada sedimentary basin hosts about 12 billion bbl of conventional oil in Devonian to Cretaceous reservoirs. Lower Cretaceous oil sands contain an additional 1.3 trillion bbl in place. The oil sands represent the biodegraded remnants of supergiant conventional oil deposits, the source for which has been thought to be mature rocks of the equivalent-age Mannville Group. This work shows, however, that the known Mannville rocks alone are incapable of generating the required volume of hydrocarbons. The volume of hydrocarbons generated in the Mannville beneath central Alberta was calculated by combining measured geochemical and geologic data with Lopatin's method for thermal maturation. Original hydrocarbon-generative capacity of the Mannville rocks was calculated from geochemical analyses of immature samples. Using average values for total organic carbon (TOC) (1.3%) and Rock-Eval hydrogen index (100 mg HC/g TOC), maximum hydrocarbon generation per unit volume of source rock was calculated. The maturation model was then employed to estimate the extent to which maximum yield has actually been achieved. Total volume of source rock in the basin was obtained from isopach maps of Mannville shale. Multiplication of actual oil generation per unit volume by source rock volume gave a generated volume of 450 billion bbl. These calculated values are exceedingly optimistic, however, because they ignore inefficiencies in expulsion and migration. Inclusion of oil generated in Mannville-equivalent source rock in the Foothills belt would less than double this quantity, assuming that source potential there is similar to that of the central Alberta rocks. It is clear that the Mannville Group of the Western Canada sedimentary basin cannot be the major source of Alberta's oil-sand hydrocarbons. Either the hydrocarbons were generated in as yet undocumented, very organic-rich Mannville-equivalent rocks in the Foothills, or they are derived from multiple sources throughout the basin.

Overthrust Problem--As Exemplified in Western Canada: ABSTRACT

The Western Canada sedimentary basin contains tar deposits in Lower Cretaceous sands and on the Paleozoic unconformity surface which exceed by 3 times the known recoverable oil reserves of the entire world. The tar was originally liquid oil which has been degraded by aerobic bacteria. The Athabasca anticline, a drape structure caused by Devonian salt removal, connects southward with the Sweetgrass arch to form a 600-mi long structural barrier on the eastern, updip rim of the basin. Most of the tar deposits are along the anticline or in a giant stratigraphic trap on the west flank of the anticline. There is no oil or gas east of the anticline. In the deepest part of the basin the Mesozoic section generated gas in enormous volumes. Most of the gas has escaped to the outcrop, a small amount is contained in thousands of conventional stratigraphic pools on the east side, and a very large volume is contained in tight sands on the west side, or in the Deep basin. Most of the reservoirs are Lower Cretaceous sands. The tight, gas saturated sands grade updip into porous water saturated sands. The trap is not tightly sealed but leaks off at a steady rate. Continuing gas generation keeps the trap pumped full. This bottleneck trap contains 1,700 tcf of gas in place. The gigantic oil and gas accumulations of the Lower Cretaceous make the Western Canada sedimentary basin the richest hydrocarbon province in the world. End_of_Article - Last_Page 796------------

Seismic Stratigraphic Modeling with Western Canadian Examples: ABSTRACT

The seismic response to four stratigraphic hydrocarbon traps has been analyzed using a microcomputer-based modeling system. This technique generates a suite of logs representing a gradual stratigraphic variation. Synthetic seismic traces are computed for each log and displayed as a model seismic section. The capabilities and limitations of the technique are illustrated by the following case histories: (1) Middle Devonian reefs in central Alberta, (2) Middle Devonian reefs in northwest Alberta, (3) Lower Cretaceous channel sands in eastern Alberta, and (4) Lower Cretaceous channel sands in southern Alberta. End_of_Article - Last_Page 469------------

Regional Trends in Transmissivity and Hydraulic Conductivity, Lower Cretaceous Sands, North‐Central Texasa

ABSTRACTDepositional and structural history control regional trends in transmissivity and hydraulic conductivity in Lower Cretaceous‐age sandstones along the Balcones‐Ouachita trend in north‐central Texas. Because of a scarcity of pumping tests, delineation of trends was possible only by incorporating transmissivities estimated from specific capacities. Statistical comparison of estimated and pumping‐test transmissivities confirmed the validity of this approach. The resulting contour maps should be useful in evaluating these aquifers as potential low‐temperature geothermal resources. The method can also be applied to other aquifers to facilitate ground‐water management programs.

A Preliminary Study Of The Hibernia Field

Abstract The Government of Newfoundland and Labrador Petroleum Directorate, in conjunction with INTERCOMP has conducted a preliminary investigation of various depletion schemes for the Avalon and Hibernia reservoirs within the Hibernia Field. Five wells have been drilled in this field to date which confirm the existence of substantial quantities of oil and gas reserves in at least two major reservoirs. A description of each reservoir was based on interpretation of the existing seismic. geological, petro physical and production test data. Reservoir simulation models were constructed for each reservoir to examine the effect of various recovery mechanisms. The results presented in this study are considered to represent only a minimal degree of optimization due to the limited reservoir description presently available. This paper focuses on the results of the reservoir simulation study. A brief description of the major geological and fluid characteristics and a discussion of the impact of these characteristics on depletion strategies for each reservoir are provided. In addition, the major uncertainties and potential problem areas which may require further investigations are identified. The simulation results with respect to production rates and recovery are also presented for typical development strategies for each reservoir. Preliminary studies of this nature are considered as the beginning of a series of progressively more complex studies which are essential to the efficient and optimum development of offshore reservoirs. Introduction The Hibernia Field is located approximately 320 km southeast of St. John's, Newfoundland, as shown in Figure 1. The water depth in this region is approximately 80 metres. The Hibernia Field was discovered in September 1979 with the drilling and completion of the well Chevron et al. Hibernia P-15. Four subsequent wells Mobil et al. Hibernia 0-35, B-08, G-55A, and K-18 have been drilled confirming the existence of major hydrocarbon-bearing sandstone units in sediments of Jurassic and Lower Cretaceous age. These major sandstone units have been identified as the Jeanne d'Arc zone in the Jurassic sands, and the Hibernia, Avalon and the Seismic B-Marker (Catalina) zones in the Lower Cretaceous sands. The potential hydrocarbon-bearing zones encountered in each of the wells are summarized in Table 1. F1GURE 1. Hibernia Field location.(Available in full paper) TABLE 1. Summary of hydrocarbon-bearing zones-Hibernia Field (Available in full paper) Productivity potentials of 2485–3180 m3/D per well have been indicated based on the drill-stem tests results from the wells P-15 and O-35. The differences in reservoir development encountered in the five wells confirm that the hydrocarbon accumulation consists of multiple, possibly non-communicating, sand layers within a complex structure that is folded and faulted. Based on the results of the five wells, the majority of the hydrocarbon reserves are interpreted to be located in the Avalon and Hibernia reservoirs. The subject matter of this paper is therefore based on a study of these two reservoirs. As the title of the study suggests results and conclusions presented herein are preliminary. The subject study includes data which were available on April 30, 1981 and does not include data acquired from Mobil et al. Hibernia K-18 and J-34 or the 3-D seismic program.

Use Of Magnetic Ranging Logging Tool To Direct Amoco . Steep A7-28-66-07 W6M Drilling

Abstract Amoco et al. Steep A7–28–66–7W6M was drilled as a directional well to 2395 m M.D. to intersect Amoco et al. Steep 7–28–66–7W6M which had blown out. The replacement well was to be used to perform a bottomhole-kill operation and then subsequently converted to a producing well. As the precise bottom hole location of Steep 7–28 was unknown, a method for estimating the proximity of this wellbore to the Steep A 7–28 wellbore, while drilling, was required. A "Magrange II" logging tool, used to detect the presence of magnetized steel in remote bore holes, provided both direction and distance from the logging tool to the abandoned drill string in the Steep 7–28 wellbore. This information was used to direct the drilling progress of Steep A7–28 toward the blowout well. A separation of approximately two metres between the wellbores, at 2331m. T.V.D. was achieved. The kill operation was subsequently conducted through a completed wellbore. Introduction The Amoco et al. Steep 7–28–66–7W6 well blew out upon penetration of the Spirit River " F" conglomerate at a depth of 2338 m M.D. (7669 ft). Located approximately 60 km (40 mi.) south of Grande Prairie, Alberta in the heart of the Elmworth Deep Basin, the well was drilled as part of Amoco Canada's program to test the massive Lower Cretaceous sands, principally for their tight gas potential. Assessment of the kick data from Steep 7–28 and of data from two other wells which had encountered this conglomerate in Township 66–8W6 revealed the Fahler " F" to have an over pressured gradient of approximately 12.5 kPa/m (0.55 psi/ft) with a deliverability of sweet dry gas, in the range of 425–1000 × 10m3/d (15–35 mmcfd), typical of high permeability conglomerates. After controlling the blowout, a fishing job was undertaken to recover the stuck drill string and save the well The Steep 7–28 well was left with the bottom 1100 m (3600 ft) of drill string in the hole and a fishing string hanging from the wellhead. A small amount of gas continued to flare at surface as the 7–28 well could not be shut-in due to a lack of casing in the Wellbore. With 1890 m (6200 ft) of open hole exposed and at least partially collapsed around the drill string, the possibility of underground blowout, or uphole charging of permeable formations, necessitated the drilling of a relief well, Steep A7–28–66–7W6 to effect a bottomhole kill at Steep 7–28. Steep A7–28 was designed with the following factors in mind:overpressured gas-the well was designed as a producer for high pressure, high deliverability gas.deliverability-in order to complete a bottom hole dynamic kill of 7–28, a fluid pump rate capability down the well of 20–25 m3/min. (125–160 bpm) had to be accommodated.breakthrough gas-any overcharged uphole formation could cause premature connection between A7–28 and the Fahler " F" of 7–28.hole problems-Blackstone and Shaftsbury shales are known problem zones in this area.directional drilling-the well was to be drilled to intercept 7–28.

The Gronlid crossing, Saskatchewan Provincial Highway No. 6 at the Saskatchewan River

A traffic connection between Regina and the northeastern part of Saskatchewan required a crossing of the Saskatchewan River north of Gronlid. Slope instability developed in lacustrine and deltaic sands on the approaches to a ferry site installed in the early 1960s. Alternative ferry sites were considered but a river hydraulics study showed that other sites would not offer any improvement. The creation of a reservoir by projected dam at Nipawin and potential mining development in the area added incentive for the construction of a bridge to replace the original ferry installation.Valuable information was obtained from the ferry site for locating the new bridge and designing the approach roadways. It was possible to locate the bridge and approaches to minimize seepage, foundation, and slope instability problems in a deposit of over 100 m of saturated interbedded deltaic sand, lacustrine silt, and clay. A major artesian groundwater system was found in the bedrock sand of the Swan River Group, whereas groundwater conditions in the surficial stratified drift were mainly hydrostatic.The regional geology was used as a basis for detailed stratigraphic analysis at the site. The stratigraphy consisted of Lower Cretaceous sand and clay shale units underlying a dense unoxidized till. The site geology was divided into three parts: (1) the south valley approach, (2) the river channel crossing, and (3) the north valley approach. The bridge was completed in the summer of 1980.

Sedimentology of Lower Cretaceous Subtidal Sand Complex, Woburn Sands, Southern England: ABSTRACT

The Lower Cretaceous Woburn sands have long been considered a transgressive and partly open marine tidal sand deposit. They form a 60-m thick, northward-wedging sandstone body between Jurassic shales, which they unconformably overlie, and a transgressive marine clay which oversteps them northward. Our studies identify three southward-imbricated, erosionally bounded sand units as follows. Orange Sands (oldest) comprise alternations of cross-bedded, channel-fill sands and thinner bedded, bioturbated, heterolithic sands. Bidirectional paleocurrents show a dominant northeasterly flood direction. Silver Sands are characterized by tabular cross-bed sets (up to 3 m thick) which overlie subhorizontal, low-angle (4 to 8°) or concave-upward erosion surfaces. Bidirectional paleocurrents reflect a slight dominance of the southwesterly ebb direction. Red Sands (the youngest) are structurally similar to the Silver Sands but are distinctive on the basis of abundant detrital ferric oxide and strong horizontal burrowing. Northeasterly dipping cross-bedding is relatively uncommon, producing an overwhelmingly dominant southwesterly, ebb-directed paleocurrent mode. The interfingering of high-energy tidal channel-fill deposits and heterolithic beds is typical of subtidal estuarine deposits. Furthermore, the upward decrease in the proportion of heterolithic facies and burrowing intensity, the upward increase in the proportion of large-scale cross-bedding and channel width/depth ratios, End_Page 728------------------------------ and the upward transition from flood to ebb dominance are interpreted as reflecting the onlap of estuary-mouth sands over inner estuarine channel/shoal deposits. The closest modern analogs to this type of transgressive sequence are the estuarine retreat sand complexes on the eastern United States shelf. End_of_Article - Last_Page 729------------

Geology of Southeast Georgia Embayment: ABSTRACT

Computer-generated lithology-porosity calculations based on corrected sonic, density neutron, and gamma-ray logs can aid greatly in interpreting the rock record. Percentage shale calculations averaged over uniform intervals show one-to-one correlation with environmental interpretations derived from micropaleontologic data for Upper Cretaceous rocks in the COST GE-1 well. For the marine section percentage quartz parallels percent shale and both follow the general trend of transgressions and regressions suggested by P. Vail et al. The transgressive pulses at the GE-1 site are quite similar to those at the B-2 site. The depositional sequence is similar at the two sites, with both containing Upper Cretaceous shelf carbonates, Lower Cretaceous nonmarine clastics, and a decreasing rate of deposition with time. Lower Cretaceous Albian anhydrite present at GE-1 is absent at B-2. Conversely Lower Cretaceous coal, End_Page 452------------------------------ abundant at the B-2 location, is absent at GE-1. Given the otherwise similar stratigraphic sections, these differences are believed mainly climatic in origin. Porosity in GE-1 Lower Cretaceous sands shows only slight decrease with depth. End_of_Article - Last_Page 453------------

Lower Cretaceous Geology And Heavy Oil Potential Of The Lloydminster Area

Abstract Lloydminster comprises the most southerly deposit of the Alberta-Saskatchewan Mannville heavy oil sand belt. Hydrocarbon entrapment is controlled in part by updip sand pinchout, but is related primarily to regional anticlinal closure associated with salt solution of the Middle Devonian Prairie Evaporite Formation. This area, with oil gravities ranging from 10 to 25 degrees API, differs from the rest of the "heavy oil belt" in that it has demonstrated primary recovery. Manllville sedimentation in the Lloydminster area was influenced by paleotopography and structure on the pre-Cretaceous unconformity surface. Widespread emergence accompanying the Paleozoic unconformity resulted in non-marine, mainly fluvial; deposition in the Basal Dina Clastic Unit. Maximum marine incursion occurred during Sparky time, and the remainder of the Mannville was a complex intertonguing of near-shore, deltaic and alluvial facies. "Widely developed channel fill deposits in the uppermost Mannville over much of the area indicate a return to emergent conditions which were terminated with transgression and inundation by the Colorado Sea. Higher sand content in the northeastert1 part of the area and mineralogy indicate that sediment source was the Precambrian Shield. The Mannville sands of the Lloydminster area contain more than 16 billion barrels of oil-in-place. The reservoirs that have demonstrated primary production and Were included ill this estimate comprise the Colony, McLaren, Waseca, Sparky, GP, Lloydminster and Cummings sands. The Sparky is the most prolific producer. The Cummings and Colony wilts have been minor contributors to date. Introduction The LIoydminster area, outlined in Figure 1, comprises a 10,750-square-mile (27,840 km2) rectangular block spanning the Alberta-Saskatchewan border between Townships 42 and 55 and Ranges 17 west of the Third meridian and 10 west of the fourth meridian. The border city of Lloydminster, the center of drilling and production activity, is situated in the north-center of the block. Edmonton, the provincial capital of Alberta, is 140 miles to the west. The Lloydminster heavy oil accumulation is the southern extension of a discontinuous trend of Lower Cretaceous bitumen and heavy oil sand deposits extending from Athabasca through Cold Lake to Lloydminster. Other ol sand deposits occur at Wabasca and Peace River. The Lloydminster pools, many of which are produced by conventional methods at the present time, contain oil ranging from 10 to 25 degrees API (1000-904 kg/m'). Enhanced recovery processes, where economical, have significantly increased production, with waterflood as much as doubling the 4 per cent primary recovery expected in some fields, Thermal recovery pilots have demonstrated considerably higher recoveries, but so far have proved to be marginally economic at best. This paper will outline the Lower Cretaceous Mannville depositional framework, illustrate selected depositional environments and describe an oil-in-place assessment for the area. History Lower Cretaceous oil was encountered in the L1oydminster area near Wainwright, Alberta in 1923. Although this discovery was soon followed by several significant shows, commercial production was not established until 1944, with development of the Silverdale Sparky sand pool 6 miles south of the city of Lloydminster, This led, in 1946, to the cons(ruction of the Husky refinery at Lloydminster and to a short-lived drilling boom that pushed production to nearly one million barrels in 1947.

Mineralogy of manganese oxides from Groote Eylandt

The manganese ores on Groote Eylandt occur in a flat-lying horizon in a series of Lower Cretaceous sands and clays which overly unconformably the Middle Proterozoic sandstone basement. The ore horizon exhibits a variety of textural and compositional ore types. Textural types include pisolites and concretions, either free or cemented into massive, bouldery or pebbly horizons. Compositional variations result from varying degrees of admixture of the manganese materials with the sands and clays of the formation. — The ore minerals are pyrolusite and cryptomelane, with minor amounts of lithiophorite, psilomelane, nsutite and todorokite. Gangue minerals include kaolinite, quartz and goethite. — Mineralogical studies indicate that three microtypes of cryptomelane occur. Low levels of cobalt, nickel and zinc in certain of the ore types are associated with the mineral lithiophorite.

EVALUATION OF THE WINDALIA SAND, BARROW ISLAND AN EMPIRICAL APPROACH

The Barrow Island oilfield derives 97 percent of its 46,000 barrels per day production from the Lower Cretaceous Windalia Sand. The lithology of the sand, which is 110' + 20' thick across the field, is very finegrained, glauconitic sandstone, shaly and silty in parts and varying from moderately unconsolidated to firm. Thin, hard beds of dolomitic and calcareous, sandstone occur throughout. The sand has high porosity and low permeability.The argillaceous and unconsolidated nature of the formation precludes the use of log interpretation methods based on standard parameters, and it was decided to develop an empirical log evaluation method. In order to calibrate the logs, sixteen of the early wells were fully cored and logged, and the data compared using the Holgate method, which allows two parameters to be correlated to determine their relationship. In the example which is the subjert of this paper, core porosity was correlated against both sonic transit time and bulk density and hence calibration of these log parameters was obtained.The best fit straight line relating porosity and sonic transit time has its origin at 76 microseconds per foot and extrapolates to 246 microseconds per foot at 100 percent porosity. The bulk density — porosity cross plot gives a grain density of 2.71 grams per cubic centimetre and fluid density of 1.16 grans/ cc. The deviations from the standard parameters of delta-t matrix = 56. delta-t fluid = 189, grain density = 1.65, fluid density = 1.0 are explained by the shaliness and lack of compaction of the formation. Using charts for the calculation of water saturation and porosity from induction conductivity and sonic transit time (or bulk density) at 2' intervals through the sand, backed up with traced SP and caliper curves, an evaluation plot of standard format is developed. Intervals of nett effective pay are then chosen.Other evaluation techniques used during the development of the Windalia Poo! include a modified movable oil plot, used in the water injection wells where a saturated saline drilling fluid was employed, and a Sonic-Neutron log comparison for the identification of suspected gas columns in the Windalia.440 wells have now been drilled at Barrow Island, and the empirical evaluation methods evolved have enabled the definition of beds of producible hydrocarbons in all cases.

Developments in Northern Rockies in 1967

Exploratory drilling decreased in 1967 but success ratios were better in Wyoming and North Dakota. Development drilling increased, but production declined. Developments late in 1967, however, should result in an increase in all categories in 1968. The most significant developments in the Northern Rockies were the discoveries in the Lower Cretaceous Muddy sand at Bell Creek in Montana, and Recluse and Kitty in Wyoming. These discoveries have led to lease and drilling activity in Montana, North Dakota, South Dakota, and Wyoming, which will lead to extensive exploration in these states in 1968. The significance of Bell Creek is the fact that this large accumulation was found through a program of stratigraphic drilling and could not have been found by any other conventional e ploration program. The northern Powder River basin continues to be the most active exploration area in Wyoming; however, the target for exploration has shifted from the Minnelusa to the Muddy. New Minnelusa pools continue to be found adding to the previously discovered reserves. The discovery of a significant accumulation in southeastern Montana at the Bell Creek field sparked the drilling of wildcat wells based on scant geologic information. The result was several dry holes and no additional discoveries which caused a low discovery ratio for the area and state. The Tiger Ridge gas field appears to be a large field by Montana standards, and probably will prove to be one of the larger gas accumulations in the state. Discoveries and new pays in the Williston basin assure continued exploration in this area both central Montana and the Sweetgrass arch had some exploratory activity and success. North Dakota remains an attractive area in which to operate because of shallow depths, low drilling costs, available acreage, and a favorable market and price for oil. Continued exploration for and discoveries in deeper pays both on and off the Nesson anticline offer incentives to keep deeper exploration alive in search for large stratigraphic traps. Bell Creek already has touched off major lease activity in this state which will lead to considerable Newcastle (Muddy) exploration in 1968. South Dakota's reserves still elude the explorationist; the impact of Muddy discoveries in Wyoming and Montana probably will lead to exploration for this objective in South Dakota in 1968. There was no drilling in Idaho in 1967.

THE BARROW ISLAND OILFIELD

Barrow Island lies 35 miles off the northwest coast of Australia, 800 miles north of Perth, and has an area of 90 square miles. Miocene Trealla Limestone crops out over most of the island. Eocene Giralia Calcarenite is found in some valleys of the crestal region and Quaternary sand covers the island fringes.The Barron No. 1 well was located at the highest point in the sub-surface, as indicated by seismic refraction work, and in the crestal area of a gently dipping surface anticline. It was mapped as having at least 80 feet of vertical closure with an area of 24,000 acres. This well was completed as a new field discovery in August, 1964, with an initial production rate of 985 BOPD from sand in the Jurassic. In February, 1965, Barrow No. 4 was completed as a shallower pool discovery with an initial production rate of 125 BOPD from a Lower Cretaceous sand. By December, 1966, 33 wells had been drilled for a total footage of 155,409 feet.Barrow No. 1 is the deepest well at 9875 feet although it is considered that the sedimentary section may exceed 20,000 feet. The known sequence begins with Upper Jurassic siltstones. These pass upwards into a predominantly sandstone sequence containing minor shale and siltstone, and are followed by the dark-coloured marine shales and siltstones and minor sandstone of Lower Cretaceous age. In the Upper Cretaceous and Tertiary, fossiliferous, micro-crystalline Limestones and calcareous siltstones were deposited.The field contains two petroliferous intervals. The deeper interval is within the Upper Jurassic and contains a number of small irregular pools with good reservoir characteristics, these, however, are not commercial in themselves. The shallower interval contains the widespread "Windalia Sand" which has an average pay thickness of 44 feet and generally poor reservoir characteristics. Drilling is now developing the "Windalia Sand" pool which covers 24,700 acres and contains reserves currently estimated at 114 million barrels recoverable by primary methods. Structure at this pay horizon is a broad north plunging nose truncated at the south by a down-to-the- south fault. One hundred and forty-four development wells will he drilled in 1967.

GEOPHYSICAL CASE HISTORY—BLACK HOLLOW FIELD, WELD COUNTY, COLORADO

The Black Hollow Field is located in Weld County, Colorado, on the west flank of the Denver‐Cheyenne Basin. The producing reservoir is the Lyons sandstone of Permian age. Seismic work was begun in the area in 1944, following up gravity leads resulting from a gravity survey done in 1943. A minor lead resulted, but it was not until 1949 when The California Company moved in a Western Geophysical crew for additional seismic work that structural closure was recognized. This led to the drilling of a well to test the Lower Cretaceous Dakota and Lakota sands, which were then the major objective. The well was abandoned in 1952. During the next year, interest increased in Permian objectives and the well was re‐entered and deepened to the Lyons, thereby becoming the discovery well at Black Hollow. Subsequent development drilling indicated anomalous thickening and stratigraphy on the west flank which led to more seismic work. Results indicated that this could be mapped. Furthermore, a velocity gradient across the area was recognized, and applying this, the possibility of extending the field to the east was recognized. More seismic work was done in an attempt to confirm this prior to additional drilling.

Tectonics of Central Montana: ABSTRACT

Central Montana has been tectonically active at least since pre-Devonian time. This activity has been in seven stages: (1) pre-Cambrian to post-Devonian uplift and erosion, (2) early Mississippian Big Snowy downwarp, (3) Heath uplift, (4) pre-Jurassic epeirogeny, (5) late Laramide orogeny, (6) late Eocene or post-Eocene igneous intrusions, (7) pre-Pleistocene epeirogeny. The late Laramide orogeny and late Eocene or post-Eocene igneous intrusions account for the asymmetrical (Big Snowy Mountains) tectonic features and the laccolithic domes (Judith Mountains) visible to-day. Accumulation of oil in central Montana is found in both structural (Cat Creek field) and a combination of stratigraphic and structural traps (Northwest Sumatra field). Geologically the oldest producing ormation is the Mississippian Kibbey sand (Ragged Point field) and the youngest is the Lower Cretaceous First Cat Creek sand (Cat Creek field). The conclusion can be made that central Montana tectonics were not restricted to Laramide time. Oil has been found in lenticular or isolated sandstones but very little has been found in the widespread sandstones of the Jurassic and Lower Cretaceous. One may speculate that oil which initially accumulated in these sands migrated from the central Montana area or its margins prior to the late Laramide orogeny. The subsequent cropping out of the Jurassic and Lower Cretaceous strata during late Laramide deformation and erosion caused an increase in formation hydrostatic pressures making it more difficult for the oil to migrate back into central Montana and into the present structures. End_of_Article - Last_Page 788------------