Bbls Of Oil Research Articles

Origin, distribution, and CO2 EOR and CO2 storage resource assessment of selected residual oil zone fairways in the Illinois Basin

Residual Oil Zones (ROZs) are volumes of rock with low, largely immobile, oil saturations that provide opportunities for low carbon intensity oil production via carbon dioxide enhanced oil recovery (CO2-EOR) and associated CO2 storage. Oil shows of varying degree have been observed throughout the Illinois Basin (ILB). This work is the first to assess these shows as ROZs.In the ILB, the distribution of ROZ fairways and prospects is controlled by the geologic setting and oil migration history of the basin. ILB ROZ fairways that are stratigraphically proximal to the source rock are generally widespread whereas fairways developed in formations with a greater thickness of intervening strata are more discrete, an indication of influence from fault systems and fracturing associated with major structures. Within these fairways, 41 ROZ prospects were defined across three formations (Tar Springs Sandstone, Cypress Sandstone, Carper Sandstone) containing a best estimate (P50) of five billion barrels (bbls) of original oil in place (OOIP). For context, this volume is 35% of the estimated 14.1 billion bbls of OOIP in the conventional reservoirs in the ILB. In comparison to the Permian Basin, the ILB ROZ OOIP volume is 20% of the estimated 25 billion bbl of ROZ OOIP within a nine-county area of the San Andres Formation.The CO2-EOR resource of the ILB ROZ prospects exceeds 518 million bbls of oil using CO2 injection via pattern flooding. Associated CO2 storage is estimated to be 411 million tonnes of CO2. This study builds on past efforts to establish the CO2-EOR and associated CO2 storage resource potential of the ILB and presents a methodology that can be used to assess ROZ resources in other parts of the world.

Anaerobic activation of microorganisms indigenous to oil reservoirs to enhance oil recovery

Microbial enhanced oil recovery focuses on the activation, isolation, and screening of aerobic functional bacteria. Air injection is required to activate aerobic microorganisms for use in indigenous microbe oil displacement technology. In practice, however, oil reservoirs are oxygen-free, as the oxygen in the air is rapidly consumed by reducing substances and aerobic microorganisms attached to the water injection well at the front end of the reservoir. In the reservoir, most of the microorganisms metabolize anaerobically, and they are concentrated in the area where the residual oil collects in the rear of the facility. The aim of this study was to investigate the factors such as electron acceptors, activator components, and activator concentrations that influence anaerobic metabolism in indigenous microorganisms. Core flooding tests and field trials were conducted to evaluate the anaerobic microbial activation efficiency. The organic nitrogen source in the activator was crucial to anaerobic bacterial metabolism. Yeast powder was the preferred nitrogen source, and other optimal operating parameters included a C/N ratio of 20:1 and an activator concentration of 3 g·L−1. Under these conditions, the anaerobic emulsification index surpassed 90%. Core flooding tests demonstrated that microbial enhancement may provide up to 13.5% oil recovery. A total of 3471.15 BBLs of oil was recovered by injecting anaerobic activator into the Zhan3-15 well, and emulsified oil droplets were detected in the fluid. The results of this study could provide technical support for the practical anaerobic activation of reservoir microorganisms and the improvement of microbial enhanced oil recovery.

Utilization of produced condensate for enhanced oil recovery: a case study for the forest reserve field in Trinidad

The current global economic trends of low commodity prices for hydrocarbons, competition due to the emergence of shale oil and gas, as well as the decline in production from mature oilfields in Trinidad and Tobago (TT) have fuelled the need for the implementation of efficient and enhanced oil recovery methods. Of particular concern locally is the issue of decreasing oil production and increasing production costs in mature oil fields due to the prevalence of organic deposits (paraffin or asphaltenes), which results in the coating of production tubing causing the plugging of surface equipment, pipelines, perforations and pore spaces in the geological formation. Major deposition compound paraffins and asphaltene are soluble in condensate, which is relatively cheap and is produced as a by-product and flared in TT, and it is already used as a pipeline diluent and cleaner for deposits. The strategy of utilizing this “waste” solvent as an economical and environmentally friendly strategy for EOR was worth investigation. The FR 1346 RD well was selected for evaluation, and a pilot test was conducted using the compositional reservoir simulation model (CMG–GEM). Laboratory studies were conducted using a constructed pressure permeability flow chamber, and results from the device indicated that an asphaltene plug decreased the permeability by approximately 24%, but after treatment with condensate, there was an improvement in permeability of approximately 10% (300 md to 420 md). Tuning of the simulation model incorporating the laboratory-derived permeability data resulted in an increase in production rate to 35 bopd, which matched very closely with the field pilot well test result of an increase of 46% (from 20 to 39 bopd) when the condensate soak was performed. This increase translated in an overall gain of 30,531 bbls of oil associated with a financial gain of approximately $4.7 MM TT per well over the 16-year period. Injection types including condensate, carbon dioxide and nitrogen yielded the production of the same order. This study offers compelling evidence that the use of produced condensate in EOR is an economically and environmentally friendly strategy in TT.

Reservoir Evaluation and Volumetric Analysis of Rancho Field, Niger Delta, Using Well Log and 3D Seismic Data

Exploration and exploitation for hydrocarbon are associated with a lot of complexities, it is therefore necessary to integrate available geologic models for accurate hydrocarbon prospecting and risk analysis. This study is aimed at determining the structural, petrophysical and volumetric parameters for reservoir evaluation within the Rancho field. 3D seismic data was used for evaluating the hydrocarbon potential of the field. A suite of well logs but not limited to gamma ray logs (GR), deep resistivity log (DRES), neutron log (NPHI) and density log (RHOB) from four (4) wells were employed in characterising dynamic properties of the reservoirs. The GR log was used in lithology identification while the resistivity log was used in identifying probable hydrocarbon bearing sands. A correlation exercise was carried out to identify lateral continuity and discontinuity of facies across the wells. Thereafter petrophysical parameters were analysed from the suite of wire line logs. Major faults were mapped on the 3D seismic data and identified hydrocarbon bearing sand tops from the well logs were mapped as horizons on the seismic section, maps were generated and volumetric analysis was done. Nine (9) hydrocarbon sands (Sands A - I) were identified within the study area. The well log revealed an alternation of sand and shale layers as well as shale layers increased in thickness with depth, while the sand bodies reduced in thickness with depth which characterized the Abgada Formation of the Niger Delta. The effective porosities of the sands range from 21% - 31%, the permeability ranges from 28% - 44%, 70% - 80% for the net to gross, volume of shale range from 14% - 40% and hydrocarbon saturation ranges from 63% - 82%. Twelve (12) faults were mapped within the study area and the structural styles revealed a fault assisted closures. The volumetric analysis showed that Sand F had Stock Tank Oil Initially In Place (STOIIP) of 5,050,000,000 bbls of oil and Sand G had STOIIP of 17,870,000,000 bbls, these sands are proposed to be developd because of the volume of oil in them and area covered by the reservoir, calculated Gross Rock Volume (GRV) of 29.5 km3 and 104.5 km3 respectively.

An opportunity to re-evaluate the petroleum potential of the Douala/Kribi-Campo Basin, Cameroon

The recently announced Cameroon licence round running until 29 June 2018 provides oil companies with a significant opportunity to acquire large swathes of acreage in the Douala/Kribi-Campo (DKC) and Rio Del Rey (RDR) Basins. The DKC Basin is divided into two sub-basins, the Douala Sub-basin in the north and the Kribi-Campo Sub-basin in the south. The RDR basin, situated at the toe of the Niger Delta (Figure 1), is a mature basin with significant infrastructure and production. In contrast, the DKC Basin, which is the focus of this paper, is relatively underexplored, yet there are marked grounds for optimism in its petroleum potential. The DKC Basin is separated from the RDR Basin by the Cameroon Volcanic Line (Figure 1) and is the northernmost basin formed during rifting and separation of the South Atlantic conjugate margins, a province harbouring prolific hydrocarbon accumulations. Exploration in the offshore Douala Sub-basin began in the 1960s but the first well drilled, Nyong Marine-1, was dry. It was not until the late 1970s, with the drilling of Sanaga Sud A-1 and the discovery of gas-condensate within the Aptian-Albian-aged Mundeck Formation, that exploration accelerated with the drilling of 11 discoveries in the Cretaceous, two with secondary Tertiary reservoirs. This exploration phase was primarily focused in the shallow water Kribi-Campo Sub-basin, targeting Cretaceous tilted fault-block plays, which also extend onshore, where oil is currently produced from the overlying Cretaceous Logbadjeck Formation in the Mvia Field (Figure 2). Despite the early success, production was not established until 1997 in the Ebome Field. Today, more than 1 million bbls of oil is produced annually from the Kribi-Campo Sub-basin (SNH Production Figures, 2016). The rest of the offshore DKC Basin is relatively underexplored with only 23 wells drilled in an area larger than 10,000 km2. Wells have targeted a range of reservoir intervals from the Miocene to Upper Cretaceous across a variety of stratigraphic, structural and combination traps (Figure 3). Upper Cretaceous reservoir-quality sands were penetrated by the hydrocarbon-bearing Sapele-1 well in the Etinde Exploration Block and Cheetah-1 in the Tilapia Block, although sands in the latter well were thinner than initially postulated. Strong oil shows were encountered in turbidite sands in well CM-1A in the Elombo Block. Beyond the shelf, deepwater wells Eboni-1 and Bamboo-1 (Elombo and Ntem Blocks) also targeted Upper Cretaceous sands but were water wet. Tertiary sands have been penetrated by a number of wells in the Tilapia Block, including Coco Marine-1 which flowed 34oAPI oil at a rate of 3000 bopd from the Paleocene. Oil, gas and condensate have all been recovered from various Miocene channel and fan sands across the basin, most notably from Noble’s successful YoYo discovery. This is an extension of the play behind the Yolanda-1 discovery and the producing Alen and Aseng Fields in Equatorial Guinea (Figure 2). Despite evidence for more than one working petroleum system (Tertiary and Cretaceous), hydrocarbons flowed to the surface in only a handful of wells outside the Kribi-Campo Sub-basin and the YoYo discovery looks on course to be put into production. The next phase of exploration in the Doula Sub-basin undoubtedly requires an understanding of the reasons behind this limited exploration drilling success. Previous operators have all suspected that there are challenges with source rock, timing of migration, and presence of reservoir, seal and trap but never consistently across all wells. Deciphering reasons for the apparent low well success requires a review of all exploration data in a regional geological context beyond the limits of individual blocks.

Pilot Scale CO2 EOR in Mississippian Carbonate Reservoir at Wellington Field in South-central Kansas

CO2 EOR effectiveness and CO2 retention and storage efficiencies in application to Mississippian carbonate reservoirs in Kansas were successfully tested with this small scale field project. Total of 1,101 truckloads, 19,803 metric tons, average of 120 tonnes per day were delivered over the course of injection that lasted from January 9 to June 21, 2016. Current incremental average oil production rate is 34 bbls/day and a total of incremental 6,300 bbls of oil were produced as a result of CO2 injection. Only 12% of injected CO2 was produced back currently (3 months since injection stopped CO2).

Thermal modelling of the Melut basin Sudan and South Sudan: Implications for hydrocarbon generation and migration

The thermal history of the Melut rift Basin was studied in a number of wells and along a northeast-southwest cross sectionacross the basin using 1-D and 2-D basin models. Modelling was conducted using PetroMod software to test subsidence, thermal history and their implications for hydrocarbon generation, migration and accumulations. Geotherms were found ranging between 24 and 44 °C/km and average 32 °C/km and present day heat flow was found to vary between 53 and 65 averaging 59 mW/m2. A geologicaly realistic paleoheat flow model with higher heat flow peaks of 75, 70 and 65 mW/m2 during the first, second and third rifting phases respectively, calibrated against vitrinite reflectance data was employed. The model was found sensitive to Cenozoic erosions and a 600 m of exhumation did support the vitrinite data in providing a reasonable fit in most locations. Using the Easy %Ro vitrinite kinetic model for maturity the average present day oil window was found between 1565 and 4050 m in the wells studied and between 1705 and 4200 m along the cross section. Using type-II kerogen for the Aptian-Albian source rocks, the hydrocarbon generation and expulsion were modelled and revealed that the generation started as early as 95 Ma in some areas but significant generation rates were during the second rifting phase and expulsion started at around 85 Ma. Calculations of the probable expelled amounts of hydrocarbon from the northern sub basin are high and up to 2.2 × 1011 bbls of oil and 2.3 × 1014 ft3of gas. Migration of oils from Cretaceous source rocks kitchen to the Cenozoic traps was probably through faults, porous carrier beds and breaching of traps cap rocks. The filling of these traps might be periodic during the rifting episodes and hydrocarbons remigrated from deeper traps to shallow ones. It is possible that thinner and siltier cap rocks along the hydrocarbon migration path, may have allowed gas to scape but holded the oil back. It is most probable that part of the hydrocarbons might have been generated from shallower source rocks areas and a 2-D hybrid Darcy-Flow path model have demonstrated this and predicted a number of accumulations which are similar to the known large discoveries such as Palogue-Fal and Adar-Yale oil fields.

Prospects for Commercial Bitumen Recovery from the Grosmont Carbonate, Alberta

Abstract The last few years have seen the end of the Athabasca land play and the revival of interest in Alberta's bitumen resources in carbonate reservoirs. Of these, the Grosmont Formation is the most promising in terms of resource size and concentration. It is also the best known, in terms of having been the subject of several in situ pilots operated in the late '70s and early '80s. The data recorded from these early pilots is priceless in terms of having a touchstone of reality for new process concepts. On the other hand, the interpretations written in those days ('before gravity') are not necessarily as helpful. This paper looks at the Grosmont in terms of facts and fundamentals, and presents the case for Grosmont exploitation. There is good evidence that the Grosmont has very high bulk permeability as a result of karst porosity development and fracturing. This bodes well for the use of modern gravity drainage methods in the Grosmont. Introduction Grosmont Piloting History The Grosmont Formation in north-central Alberta is a dolomitized, karsted and fractured platform carbonate containing a massive bitumen accumulation. An excellent historical summary of various Grosmont pilots was recently provided by Alvarez et al.(1) Cyclic Steam Stimulation (CSS), steam drive and forward combustion were all attempted in the Grosmont during the '70s and '80s. CSS was the most widely and successfully piloted method. The best well, at 10A-5-88-19W4, recovered about 100,000 bbls of oil over 10 cycles, with a cumulative steam-oil ratio (CSOR) of about 6. Results of other tests were mixed, as were the operating procedures; most of these were based on horizontal flooding concepts. However, responses to well-executed CSS first cycles were reasonably similar at a number of widely-spaced wells. Notably, steam injectivity was generally sufficient so that a few hundred tonnes/day could be injected at pressures that were significantly below overburden pressure (ruling out geomechanical enhancement of permeability). A degree of pessimism, or at least great caution, has been expressed with respect to the supposed complexity of the reservoir, and hence, prospects for commercial recovery. In particular, it is often said that the reservoir is very heterogenous, and that this explains the historical failure of attempted steam drive and fire flood processes. Review of the Unocal Buffalo Creek and McLean scheme reports(2, 3) suggest that much of this originates in the interpretations of the contemporary operators, who largely explored conventional EOR concepts involving horizontal displacement. They expected to recover oil by means of horizontal, radial flow. When this failed, it was natural to assume that the problem lay in a failure to maintain the 'radial' part of the prescription, due to permeability heterogeneity. Figure 1 presents the performance of the Buffalo Creek 10A-5 CSS test in perspective with a contemporary test and two modern-day, commercially-optimized CSS wells (the data is publicly available from the Alberta Energy Resources Conservation Board). It can be seen that the Grosmont well had comparable performance to a Clearwater CSS test of the same vintage.

DEMETER HIGH RESOLUTION 3D SEISMIC SURVEY—REVITALISED DEVELOPMENT AND EXPLORATION ON THE NORTH WEST SHELF, AUSTRALIA

The newly acquired 3,590 km2 Demeter 3D high resolution seismic survey covers most of the North West Shelf Venture (NWSV) area; a prolific hydrocarbon province with ultimate recoverable reserves of greater than 30 Tcf gas and 1.5 billion bbls of oil and natural gas liquids. The exploration and development of this area has evolved in parallel with the advent of new technologies, maturing into the present phase of revitalised development and exploration based on the Demeter 3D.The NWSV is entering a period of growing gas market demand and infrastructure expansion, combined with a more diverse and mature supply portfolio of offshore fields. A sequence of satellite fields will require optimised development over the next 5–10 years, with a large number of wells to be drilled.The NWSV area is acknowledged to be a complex seismic environment that, until recently, was imaged by a patchwork of eight vintage (1981–98) 3D seismic surveys, each acquired with different parameters. With most of the clearly defined structural highs drilled, exploration success in recent years has been modest. This is due primarily to severe seismic multiple contamination masking the more subtle and deeper exploration prospects. The poor quality and low resolution of vintage seismic data has also impeded reservoir characterisation and sub-surface modelling. These sub-surface uncertainties, together with the large planned expenditure associated with forthcoming development, justified the need for the Demeter leading edge 3D seismic acquisition and processing techniques to underpin field development planning and reserves evaluations.The objective of the Demeter 3D survey was to re-image the NWSV area with a single acquisition and processing sequence to reduce multiple contamination and improve imaging of intra-reservoir architecture. Single source (133 nominal fold), shallow solid streamer acquisition combined with five stages of demultiple and detailed velocity analysis are considered key components of Demeter.The final Demeter volumes were delivered early 2005 and already some benefits of the higher resolution data have been realised, exemplified in the following:Successful drilling of development wells on the Wanaea, Lambert and Hermes oil fields and identification of further opportunities on Wanaea-Cossack and Lambert- Hermes;Dramatic improvements in seismic data quality observed at the giant Perseus gas field helping define seven development well locations;Considerably improved definition of fluvial channel architecture in the south of the Goodwyn gas field allowing for improved well placement and understanding of reservoir distribution;Identification of new exploration prospects and reevaluation of the existing prospect portfolio. Although the Demeter data set has given significant bandwidth needed for this revitalised phase of exploration and development, there remain areas that still suffer from poor seismic imaging, providing challenges for the future application of new technologies.

Abstract: Upper Pennsylvanian and Lower Permian of Southeast New Mexico: Rejuvenation of Underdeveloped Fields Yields Major Reserves 

Carbonate reservoirs in the Cisco and Canyon (Upper Pennsylvanian) and lower Wolfcamp (Permian) sections in the Permian Basin of southeastern New Mexico are significant reservoirs for oil and gas. The 400 fields that produce from the reservoirs have yielded a cumulative 508 million bbls of oil and 3.2 TCF of gas. Sixteen of these fields have been identified that were underdeveloped at some stage in their history. For the 16 fields studied, redevelopment accounted for 65% of developed reserves, Redevelopment in the late 1980’s and 1990’s accounted for more than 95% of total reserves at Dagger Draw, and turned this seemingly insignificant field into the most productive field in New Mexico. Redevelopment of Dagger Draw has reversed the production decline in southeast New Mexico. Redevelopment in these fields was generally in undrilled portions of the fields and not in overlooked pay zones. Most of these fields are formed by stratigraphic traps, but initially were thought to be structural traps and were developed as such. Because initial development was on structure and off-structure areas were undrilled, most reserves remained unproduced until redevelopment. Because 9 1% of the Upper Pennsylvanian and lower Wolfcampian fields have less than 10 producing wells and have been developed primarily on structures, significant reserves may remain undeveloped in existing fields. Although initially underdeveloped, subsequent redevelopment added significantly to reserves and production.

Petroleum Geology of Pennsylvanian and Lower Permian Strata, Tucumcari Basin, East-Central New Mexico: ABSTRACT

The Tucumcari basin of east-central New Mexico is a structural depression that existed as a depositional basin from Strawn (Middle Pennsylvanian) until late Wolfcampian (Early Permian) time. Depth to Precambrian ranges from 6500 ft to more than 9000 ft. High-angle faults form the north, east, and west edges of the basin. No major structural discontinuities separate the basin from a shallow shelf to the south. Faults cut Pennsylvanian and Wolfcampain strata but generally do not offset post-Wolfcampian strata. Faults and regional structure control facies and thickness patterns within the Pennsylvanian and Wolfcampian. Coarse arkosic sands in the Pennsylvanian and Wolfcampian are good reservoirs. Those sands were deposited in northern and western parts of the basin and were derived from highlands of Precambrian granitic rocks that formed the northern and western margins of the basin. High-energy limestones are possible reservoirs in the southern part of the basin. Porous Wolfcampian dolostones cover the Frio uplift on the east side of the basin. Pennsylvanian and Wolfcampian marine shales and micritic limestones are source rocks within the Tucumcari basin. Post-Wolfcampian strata are thermally immature. Two presently noncommercial pools of oil and gas, the Latigo Ranch pool and the T-4 Ranch pool, have been discoveredmore » in Strawn sands in the northern part of the Tucumcari basin. Oil generated in the upper Paleozoic has migrated vertically into the Triassic; two oil accumulations, the Santa Rosa tar sands and the Newkirk oil pool, are in Triassic sandstones and have combined reserves of 153 million bbls of oil.« less

Factors influencing production in the toronto limestone, (Shawnee Group, Upper Pennsylvanian) Snake Creek Field, Clark County, Kansas

Commercial quantities of hydrocarbons in the Toronto Member of the Oread Formation (Shawnee Group, Upper Pennsylvanian) were discovered in November, 1980. The field subsequently was developed to include 33 Toronto wells which produce on pump assisted by a dissolved gas drive. Estimated ultimate recovery is 1,500,000 bbls of oil, based on a recovery efficiency of 35%. Cumulative primary production to January, 1986 is 91,180 stock tank barrels (STB) of 40° API gravity oil. Initial reservoir pressure was 1,700 psi, with a maximum production rate of 1,080 barrels of oil/day (BOPD). Since then, reservoir pressure has fallen to 250 psi and production has declined to 185 BOPD.

Permian (Guadalupian) Shelf Deposition and Diagenesis: Tansill Formation of Cheyenne Field, Winkler County, Texas: ABSTRACT

Cheyenne field, Winkler County, Texas, produces oil from shelf-margin lithofacies of the Tansill Formation of late Guadalupian age. The Tansill Formation encountered in the Cheyenne field compares favorably with basin-margin outcrops found in the Guadalupe Mountains of New Mexico and Texas. The Delaware basin margin consisted of (1) outer shelf ooid shoals and back-shoal green-algal flats, (2) a shelf-crest pisoid-tepee complex, and (3) inner shelf evaporitic, stromatolitic, and peloidal sediments during the late Guadalupian. The Cheyenne field reservoir exhibits varied lithologies and porosites in the Tansill Formation. Fresh-water phreatic diagenesis created moldic porosity in the outer shelf, green-algal lithofacies. Fresh-water vadose conditions existed during low sea level stands preserving intergranular porosity in the pisolitic lithofacies of the shelf-crest tepee complex. Fresh-water vadose diagenesis also helped form burrow-moldic porosity and fenestral porosity in the inner shelf peloidal lithofacies. Periodic hypersaline vadose conditions occluded some porosity with evaporites and aragonitic cements. Dolomitization of the Tansill Formation occurred in the mixing zone between a seasonal fresh-water lens in the shelf-crest sediments and the saline waters of the Permian sea and inner shelf lagoon. s sea level fluctuated the mixing zone migrated laterally. In this way, much of the Tansill Formation was dolomitized, forming finely crystalline dolomite that preserved textural details well but did little to enhance porosity. Porosity is best developed in the thin beds of the outer shelf, green-algal lithofacies. More importantly, the 194 ft (59 m) of pay in the Cheyenne field results from favorable diagenesis of lithofacies on the shelf margin that were interbedded with the shelf-crest lithofacies by fluctuations of sea level. The arid climate at the time of deposition was essential in maintaining porosity created by early diagenesis and for the absence of abundant vadose cements in the Tansill Formation. The trap in Cheyenne field is depositionally controlled by updip, nonporous, and impermeable sediments of the inner shelf lagoon. Anhydrites of the overlying Salado Formation provide an excellent seal. Interbedded End_Page 118------------------------------ lithologies of the Cheyenne field average 8% porosity and 1 md permeability. The field has recovered 499,950 bbls of oil as of May 1983, with estimated total recoverable reserves of 1,744,987 bbls of oil. End_of_Article - Last_Page 119------------

North Sea petroleum exploration

Summary After some twenty years of exploration for oil and gas, the North Sea province has emerged as the most important hydrocarbon province of Western Europe. The recoverable reserves to date discovered in the offshore area are of the order of 25 × 10 9 bbls of oil and condensate, and 100 × 10 12 scf of gas. A summary review of the history of North Sea exploration and the development of the main ‘plays’ is treated in three periods and followed by a synopsis of the complex North Sea basin evolution and sedimentary fill characteristics. Structural style and reservoir development of the hydrocarbon traps is considered in conjunction with their timely sourcing by the relevant organic-rich sediments. In conclusion, a speculative view is given on the future of exploration in an area where the most obvious plays have been extensively explored.

The Lanyard Field, a Structural-Stratigraphic Trap, Denver Basin, Colorado

Cretaceous sandstones are oil and gas productive throughout a large area in the Denver bas111. The Lanyard field is a structural-stratigraphic trap which has produced in excess of 2,388,000 bbls of oil and 4.1 Bcf of gas from the D Sandstone. Productive sandstones are interpreted to be channel deposits on the basis of subsurface mapping and core examination. Seven Cretaceous stratigraphic intervals from the Lanyard field area were identified from well data. Thickness variations on these isopach maps are caused by unconformities, convergence. and normal faulting. Thickness variations caused by unconformities and convergence may be related to paleostructure: variations caused by normal faulting are post depositional and related to Laramide (present) structure. Analyses of the seven stratigraphic intervals clearly show that paleostructure influenced D depositional patterns. D channel sandstones accumulated 111 a northeast-trending paleostructural low. Present-day structure 1s a southwest-plunging nose. The trend and location of the nose coincides with the trend and location of the D channel system. Thus. the paleostructural low has undergone structural inversion and is now a structural high. Knowledge of paleostructural control on reservoir facies provides a new idea for petroleum exploration in the D Sandstone of the Denver basin.

Wattenberg and Spindle Fields--Paleostructural and Stratigraphic Traps, Denver Basin, Colorado: ABSTRACT

The most important mineral resource activity in Colorado during the past decade has been the discovery and development of the Wattenberg gas field and the shallow overlying Spindle oil and gas field. Located north of Denver near the axis of the Denver basin, Wattenberg is estimated to have reserves of 1.3 Tcf of gas in the tight J sandstone (delta front) reservoir over an area of 600,000 acres (240,000 ha.), at depths of 7,600 to 8,400 ft (2,316 to 2,560 m). Spindle field, in the south-west part of the Wattenberg field, produces from two marine sandstone bar complexes (Terry and Hygiene Sandstones) in the middle part of the Pierre Shale. From an area of 30,000 acres (12,000 ha.), total production is in excess of 28,000,000 bbls of oil and 100 Bcf of gas at depths of 4,0 0 to 5,000 ft (1,219 to 1,524 m). Although both fields are regarded as stratigraphic traps, paleostructural analysis of the area clearly shows that during middle Cretaceous the fields were located on an ancient structural high that was subsequently downwarped into the present low structural setting. Evidence for recurrent movement on the paleohigh are unconformities at the top of the J sandstone and at the base and top of the Niobrara Formation, and also thinning of shale intervals and localization of marine sand bars within the Pierre Shale. The outline of the Wattenberg paleostructure is best shown by the area of truncation by erosion of the upper chalk of the Niobrara Formation over an area 10 mi wide × 50 mi long (16.1 km × 80.5 km). The east-west trend of the paleostructure changes to northeast and extends for more than 100 mi (16.1 km) into western Nebraska. Three other similar paleostructural trends can be mapped in the northern Denver basin. Knowledge of paleostructural control on reservoir facies and petroleum migration provides new ideas for petroleum exploration in Cretaceous rocks and in the deeper Paleozoic section of the Denver basin. End_of_Article - Last_Page 801------------

A CASE HISTORY OF ROUGH RANGE

Rough Range No. 1 was the first well to be drilled for oil in Western Australia in the post-war period. It was spudded on September 5th, 1953. At a depth of 1100m, the well encountered a flow of oil at a rate of 500 bbls per day from the Early Cretaceous Birdrong Sandstone. This first discovery of flowing oil in Australia set off a boom in exploration for oil that rivalled the gold mining booms of the last century. The discovery well was drilled for a total of 20 months, encountering a section of Tertiary, Cretaceous, Jurassic, Permian, and Carboniferous -? Devonian rocks. By May 1955, when Rough Range No. 1 was terminated, a further seven wells had been drilled on the Rough Range Anticline and all were dry. Late in 1955, Rough Range -9 was drilled but also proved dry. Rough Range-10 was drilled less than 200m from the discovery well but only found a thin, non-commercial pay zone.Studies of the Rough Range structure, incorporating data from all of the wells and the intense seismic mapping of the feature show that the area of closure is very small and the total accumulation could not be more than 282,000 bbls of oil in place in the reservoir.Assuming a 30% recovery factor, the accumulation is capable of producing approximately 84,600 bbls. Of this, 16,900 bbls has already been produced in a 48-day production test of Rough Range-1 A in 1955. WAPET believes that the small remaining reserves, even at world parity pricing, are not economically viable.Although the small accumulation at Rough Range No. 1 was a disappointment to WAPET, this first post-war oil well proved to be a "lucky break" and a big stimulus for oil exploration in Australia.

Geology and hydrocarbon provinces of the North Sea

The technically recoverable hydrocarbon reserves of the North Sea are currently estimated at 23 × 109 bbls of oil, condensate and NGL and 90 × 1012 scf of gas. The North Sea underwent a complex geological evolution. The oil and gas occurrences in the central and northern North Sea are tied to Mesozoic and Tertiary sediments; the gas fields of the southern North Sea are mainly contained in Permian series. The proven hydrocarbon provinces cover at best one third of the total area of the North Sea. It is estimated that in the early 1980's the oil production from the North Sea will meet 22% of the oil demand of Western Europe.

Pennsylvanian Geology of Western Mid-Continent: ABSTRACT

Pennsylvanian sediments deposited between the Sierra Grande--Frontrangia positive elements and the Central Kansas uplift-Nemaha ridge trend contain large amounts of hydrocarbons. In the Anadarko basin alone almost 2 billion bbl of oil, more than 20 trillion cu ft of gas, and up to 700 million bbl of gas liquids eventually will be recovered from Pennsylvanian reservoirs. Mocane--Laverne, Camrick, Hansford, Greenwood, Keyes, and Elk City are six major Pennsylvanian fields in the western Anadarko basin. They have up to 2 billion equivalent bbls of recoverable oil in traps ranging from anticlines to purely stratigraphic. The reservoirs range from carbonate banks to alluvial sandstone and are of Morrowan to Virgilian ages. The Anadarko and Denver basins always have been considered to be separate geologic provinces. However, during Pennsylvanian time they were part of the same geological regimen and properly should be considered together. The Amarillo-Wichita Mountains, Sierra Grande uplift and Frontrangia comprise a tectonic rim with a common orogenic history during the Pennsylvanian. The distribution of facies and depositional environments from this rim toward the stable-shelf area is similar and closely related across a broad area covering eastern Colorado, western Kansas, western Oklahoma, and parts of Nebraska, Wyoming, and Texas. Only the Anadarko basin part of this large area has been explored actively and most of eastern Colorado and western Kansas remains a relatively virgin area for Paleozoic exploration. Because the relations of facies and environments in the whole area are similar, because the basin structure and geologic history are closely related, and because the Anadarko basin has been the scene of prolific discoveries, it could follow that the Pennsylvanian potential of the relatively unexplored area of western Kansas and eastern Colorado is very good. End_of_Article - Last_Page 1906------------

Ordovician Oil in Sedgwick Embayment: ABSTRACT

The Sedgwick embayment occupies approximately 8,000 sq mi in south-central Kansas. The area is bounded on the west and northwest by the Pratt anticline and the Central Kansas uplift. The Nemaha ridge limits the embayment on the east. Late Mississippian and Early Pennsylvanian movements were primarily responsible for the development of the embayment. The most important reservoir of the Ordovician oil is the Simpson sandstone. Other reservoirs contributing significant recoveries are the Viola and Arbuckle. Simpson sandstone of the area was laid down by transgressive seas, with locally regressive phases, which invaded from a subsiding basin on the south. Source of the sand was on the north and northeast. The Sedgwick embayment has undergone two phases of exploratory activity. In the late 1920s and early 1930s the large features were found through core-drilling operations. Subsequent to World War II many new fields were found by subsurface studies and seismic activities. Fields in the Sedgwick embayment have produced approximately 303,000,000 bbls of oil. Of this total, 108,000,000 bbls, or approximately 30%, has come from Ordovician rocks. Most of the oil fields of the area which produce from the Ordovician exhibit similar geologic characteristics. Among the more important factors governing Ordovician accumulation are thinning of the Mississippian, existence of adequate reservoir rocks, and Permian structure. Proper geological application of the known factors which control Ordovician oil accumulation will result in many future Sedgwick embayment discoveries. End_of_Article - Last_Page 1689------------