Reef Oil Research Articles

Study on Multi-Scale Coral Reef Pore Structure Identification and Characterization

In order to more accurately realize the automatic identification and quantitative characterization of coral reef multi-scale pore structure, this paper has carried out such research. On the basis of using multiple information acquisition technology, it can effectively collect field measured data and indoor observation data to form a high-precision digital image of the development characteristics of multi-scale coral reef pore structure. By constructing the multi-scale structure information correlation and fusion function of coral reef pore structure, it can formulate the positioning and search strategy for the key areas of coral reef pore structure development characteristics. In this paper, a fine identification and quantitative characterization method suitable for the pore structure of “millimeter–micron–nanometer” is formed. At the same time, combined with the actual project requirements, the multi-scale pore structure feature area location method of coral reef is constructed, which combines the distribution characteristics, variation characteristics, fractal characteristics and shape characteristics in a certain range, and realizes the search of pore key areas between different scales and different regions of the same scale through the similarity matching algorithm, which can effectively realize the automatic search of key areas in the “millimeter–micron–nanometer”-scale image of coral reefs. Finally, the correctness and feasibility of this method are verified by multi-angle example data comparison. It shows that this method can effectively solve the productivity prediction and evaluation problem of coral reef oil and gas reservoirs.

A comprehensive analysis of transient pressure and rate data from CO2 storage projects in a depleted pinnacle reef oil field complex, Michigan, USA

Pressure and rate data are commonly recorded as part of a basic monitoring program in CCS projects. This paper discusses the application of multiple analytical techniques to interpret pressure and rate transient data from CO2 injection and storage operations. The techniques of interest, i.e., injection-falloff analysis, injectivity/productivity index analysis and pressure pulse arrival time analysis, are commonly used in the oil and gas industry to assess reservoir properties, but not well known in the CCS literature (especially the last two). Injection-falloff analysis involves log-log pressure derivative plotting for the falloff data and history-matching of the entire injection-falloff sequence to determine permeability. In the injectivity/productivity index analysis, rate-normalized pressure buildup is plotted against material balance time or ratio of cumulative injection to injection rate to determine the injectivity index (ratio of injection rate to stabilized pressure buildup) which can be related to the permeability-thickness product. The arrival time analysis identifies the arrival of a pressure disturbance (∼0.1 psi change from ambient) to determine the hydraulic diffusivity from which permeability can be estimated. The applicability of these techniques is demonstrated via illustrative examples from multiple wells in different pinnacle carbonate reefs undergoing CO2-EOR in Northern Michigan. The paper ends with a discussion of the relative merits of each interpretive technique, as well as recommendations that could be useful for other field projects.

Life span of oil reservoirs: Examples from three old reef pools in Alberta, Canada

After reaching a plateau, the production of oil reservoirs starts to decline, which substantially determines their life expectancy. Declining production data from three 58- to 71-yr-old oil pools in Alberta, Canada, have been documented and analyzed to show and predict their life span. Two declining phases of oil production can be distinguished: a short 4–11-yr substantially declining phase and a long 23–35-yr gradually declining phase. Well-fitted power regressions of the two declining phases of the pools have been observed with high correlation coefficients of 0.95–0.99 and used to forecast future annual oil production for the next 30 yr, yielding projected life spans of at least 88 to 101 yr. These pools have been producing oil at high water cuts of greater than 0.9 for 30–38 yr, currently more than 0.980 and 0.996, but still have potential to continue to deliver for at least another 30 yr. Production data from two pools indicate that 11% of original oil in place and 16%–26% of cumulative oil output were produced at a high water cut of greater than 0.9. These observation results can be used to judge other similar reef oil pools’ future production potential. This study provides a physical example to test the Hubbert curve and implies that the Hubbert curve should provide only the minimum future ultimate recoveries and the shortest future production times.

Combination of water flooding, water-gas influence and changes in the direction of filtration flows in reef oil fields

The development of reef deposits is complicated by the high variability of the geological and physical properties of the reservoir along strike and section, as well as the variability of the rheological properties of oil within the reservoir. The level of interaction between wells before they are put into production is not predictable. In such conditions, the organization of an effective system of stimulation of the reservoir is associated with the solution of many unique in each case technological problems. Using the example of a group of reef deposits, the experience of introducing exposure systems by various agents and their combinations (water, gas, water-gas) is summarized. It is shown that the exhaustion of natural reservoir energy is not the basis for stopping the development of an isolated section of the reef deposit. It is necessary to assess the primary direction of filtration according to the development history for the formation of a set of measures using the information received (changing the direction of filtration flows, changing or combining displacing agents), including the information for areas consisting of only two wells. The reaction features of producing wells that provide the basis for the use of flow deflect technologies are highlighted.

Where is that CO2 flowing? Using Distributed Temperature Sensing (DTS) technology for monitoring injection of CO2 into a depleted oil reservoir

A Distributed Temperature Sensing (DTS) system, along with a five-level, behind-casing pressure sensing array was installed as part of the Midwest Regional Carbon Sequestration Partnership (MRCSP) large-scale carbon dioxide (CO2) storage test in a depleted Niagaran pinnacle reef oil reservoir in Northern Michigan. The reef is being monitored during its initial reservoir fill-up period as CO2 is being injected to raise the reservoir pressure for enhanced oil recovery (EOR). DTS data are analyzed with results from the initial injection of ˜101,000 metric tons of CO2, injected between January 2017 and December 2018. This paper discusses the results of real-time DTS combined with multi-level pressure monitoring. The collection, processing, and interpretation of large amounts of data from fiber-optic-based DTS provides an opportunity to obtain high-resolution information on migration of CO2 in the reservoir.

Lessons Learned from CO2 Injection, Monitoring, and Modeling Across a Diverse Portfolio of Depleted Closed Carbonate Reef Oil Fields – The Midwest Regional Carbon Sequestration Partnership Experience

The MRCSP Michigan Basin Large-Scale Injection Project is evaluating CO2 storage and utilization in a complex of closed reservoirs at various stages of production and enhanced oil recovery (EOR) life-cycle. Since 2013, MRCSP has successfully injected and monitored the net storage of more than 600,000 metric tons of CO2 out of the goal of 1 million metric tons. A number of monitoring technologies have been tested, and various modeling approaches are being applied to evaluate CO2 migration, injectivity, capacity, and containment.

Characteristics of porosity and permeability layer of fossil Halimeda reef mineral rock of Miocene in the Xisha Islands and its genetic model

Halimeda is one of the major reef-building algas in the middle Miocene of Xisha, and one of the significant reef-building algas in the algal reef oil and gas field of the South China Sea. However, there have been few reports regarding the characteristics of mineral rocks, reservoir porosity and permeability layers, and sedimentation-diagenetic-evolution of fossil Halimeda systems. The present paper briefly introduces the relevant studies on chlorophyta Halimeda and the research status of oil and gas exploration. Through the 1 043 m core of the Xichen-1 well, we studied the characteristics of the mineral rocks and porosity and permeability of the middle Miocene Halimeda of the Yongle Atoll, identified and described the segments of fossil Halimeda, and pointed out that most of the segment slides are vertical sections in ovular, irregular or long strips. The overwhelming majority of these fossil Halimeda found and studied are vertical sections instead of cross sections. In this paper, knowledge regarding the cross sections of fossil Halimeda is reported and proven to be similar with the microscopic characteristics of modern living Halimeda; fossil Halimeda are buried in superposition; it is shown that there are different structures present, including typical bio-segment structure, and due to its feature of coexisting with red alga, tying structure, twining structure and encrusting structure are all present; and finally, it is suggested to classify the fossil Halimeda into segment algal reef dolomites. In addition, all of the studied intervals are moderately dolomitized. Secondary microcrystalline-dolosparite dominates the original aragonite raphide zones, and aphanitic-micrite dolomite plays the leading role in the cortexes and medullas; in the aragonite raphide zones between medulla and cysts, secondary dissolved pores and intercrystalline pores are formed inside the segments, and algal frame holes are formed between segments; therefore, a pore space network system (dissolved pores + intragranular dissolved pores—intercrystalline pores + algal frame holes) is established. Segment Halimeda dolomite has a porosity of 16.2%–46.1%, a permeability of 0.203×10−3–2 641×10−3 μm2, and a throat radius of 23.42–90.43 μm, therefore it is shown to be a good oil and gas reservoir. For the reasons mentioned above, we suggest building the neogene organic reef-modern reef sedimentation-diagenetic-evolution models for the Xisha Islands.

Seismic Profile Characteristics of Reefs and Hydrocarbon Detection Technology in Northwest Palawan Basin

In the hanging wall of faults which controlled the Paleocene depression in the Northwest Palawan Basin in the South China Sea, a large number of ancient terrain height reefs and thick mudstones are well developed, forming important reservoir cap combination type in the study area. Through years of exploration and development, 27 reef oil and gas fields have been discovered. In this article, the Northwest Palawan basin evolution and reef formation in this basin have been discussed, and the seismic response characteristics of reef oil and gas reservoir discovered in this basin are summarized, which lay a solid foundation for valid identification of reef reservoirs. Meanwhile, the reef reservoirs after containing oil and gas are characterized by high impedance and lowfrequency. The sparse spike inversion method and filtering method by setting threshold value of seismic attribute have been used to detect hydrocarbon bearing conditions of reefs to improve the reef reservoir exploration success rate.

Assessment of CO2 Injectivity and Storage Capacity in a Depleted Pinnacle Reef Oil Field in Northern Michigan

The Midwest Regional Carbon Sequestration Partnership is conducti ng a large-scale CO 2 injection test in a depleted Niagaran Pinnacle Reef in northern Michigan. The focus of the dynamic modeling tas k described in this paper is to evaluate the CO 2 injectivity and storage capacity of this closed carbonate reef structure. We discuss the history-matching process to characterize the closed reservoir model using primary and secondary recovery data and its validation with the field pressures in the current CO2 injection phase. Two alternative conceptual geologic models of the reef are constructed to evaluate the level of detail necessary to efficiently model dynamic reservoir behavior without compromising geologic accuracy. We find that our initial black oil formulation under-predicts reservoir pressure and hence over -predicts injectivity during the CO 2 injection phase. Transition to a compositional model is currently underway to better represent reservoir dynamics by effectively accounting for interphase and intercomponent mass transfer processes. Lessons learned from this exercise can be drawn upon for possible use in injectivity evaluation of other reefs in the region.

Alternative Conceptual Geologic Models for CO2 Injection in a Niagaran Pinnacle Reef Oil Field, Northern Michigan, USA

Abstract The Northern Pinnacle Reef Trend presents a regionally significant potential carbon dioxide utilization and storage resource. Two static earth models of a pinnacle reef were developed to evaluate the effect of increasing geologic detail on the reservoir model accuracy. The relatively simple lithostratigraphic model defines the geology on the basis of lithostratigraphy. An alternative conceptualization is based on sequence-stratigraphic constrained lithofacies and requires greater effort and geologic insight. The sequence-stratigraphic approach allows a closer approximation to porosity and permeability distributions observed in cored reefs and this approach will allow more realistic flow unit definition in these complex reefs.

Criteria for Successful Exploration for Miocene Reef Production in the Philippines: ABSTRACT

An abundance of modern geologic, geophysical, and geochemical data has been provided to interested members of the petroleum industry by the Philippine government, in cooperation with the World Bank. These data have been analyzed to assess whether more, and larger, Miocene reef fields should be expected in the Philippines. In the past decade, exploration by Cities Service (OXY), Amoco, Alcorn, and others has resulted in the discovery of several small Miocene reef and Miocene sandstone oil fields in offshore Palawan. Phillips/Shell also made a significant gas discovery of about 750 bcf in a Palawan Miocene reef that is currently uneconomic to develop given the water depth (1,090 ft) and distance from users. Miocene reefs are commonly buried within Miocene clastics, and, where these impinging clastics are porous, they allow pathways for hydrocarbons to leak from the Miocene reefs. Drape closure is an important positive factor in assessing seal risk for Philippine Miocene reefs. Source rocks to charge middle and upper Miocene reefs are typically restricted to lower Miocene horizons. Geothermal gradients are modest in much of the Philippine offshore, and only select areas provide sufficient burial to mature and expel significant hydrocarbons. It is predicted by the author that additional,more » larger, and highly profitable Miocene reef fields will be found by future explorers in areas where Miocene reefs have drape closure top seals and are adjacent to deeply buried Miocene source rocks.« less

Waterflooding Jin A Small Pinnacle Reef Reservoir With A Single Wellbore

Abstract The feasibility of implementing a pressure maintenance scheme in a small pinnacle reef reservoir in the Shekilie area of northwestern Alberta was assessed. Detailed geological and reservoir simulation studies were conducted on the single well Shekilie Keg River III Pool to Investigate lire alternatives for enhanced oil recovery in a pinnacle reef oil reservoir, with Jess than one million barrels Of original oil-in-place (OOIP). An excellent history match of the primary production performance by the simulation model provided a sound basis for studying different pressure maintenance schemes at various stages of primary depletion. A single-well waterflood recovery scheme, with an estimated recovery factor of 49.7% of OOIP. was recommended for the pool and subsequently implemented in October 1987. Actual field production and injection performance of this scheme is also included for early evaluation of the project. Introduction An oil productive Keg River biohern was found with the drilling of the Ultramar et al. Shekilie 6-13-119-7 W6M well in December 1985. This well encountered 86.4 m of net oil pay, of which 7.2 m occurs in the overlying Zama member of the Muskeg Formation, and 79.2 m in the Keg River Formation. The oil-water contact in this well is at 1825 m KB, and the bottom 39 m of porosity is water-bearing. The reservoir discovery pressure was 19481 kPa abs. No initial gas cap was present. The oil was undersaturated, with an initial gas-oil ratio of 147.5 m3/m3. The solution gas is sour and contains 6.80/0 hydrogen sulphide. The Shekilie 6–13 well began production on January 22. 1986, and has recovered 26 × 103m3 (164 mstb) of oil to December 31,1987. The producing gas-oil ratio has steadily increased, with no significant amount of water being produced. Due to declining reservoir pressure and increasing gas-oil ratios, a waterflood scheme utilizing a single wellbore was implemented in October 1987. The implementation of this single wellbore waterflood was based on the recommendations of a detailed geological review and reservoir simulation. Early waterflood performance provided useful data for recalibration of the model for ongoing waterflood performance monitoring and optimization. This paper demonstrates the successful application of reservoir simulation in formulating operational strategies and implementing reservoir management plans. Geology Oil pools of the Givetian (Middle Devonian) Keg River Formation are abundant in the Shekilie Basin of northwestern Alberta in the form of isolated patch reefs (bioherms). The seal for the oil pools occurs in overlying anhydritic and dolomitic evaporites of the Muskeg Formation. One member of the Muskeg Formation, the Zama dolomite, comprises minor segments of some Keg River oil pools at Shekilie. Source rocks of the oil are the bituminous laminates which about the base of the Keg River bioherms. Most of the Shekilie 6–13 oil reservoir occurs within the Keg River bioherm, as shown in Figure 1. The bioherm attains 132 m in height and is much broader at the base than at the crest. The crestal position occurs on the north side, which was the upwind direction during Givetian bioherm growth.

Geology of North-Central Delaware Basin, Eddy and Lea Counties, New Mexico: Its Hydrocarbon Potential, Focusing on 12 Townships Centered on WIPP Site: ABSTRACT

The Waste Isolation Pilot Plant (WIPP) site is located within the Carlsbad potash mining area, southeastern New Mexico, about 20 mi east of Carlsbad. Structurally, the WIPP site is located in the north-central part of the Delaware basin, which yields hydrocarbon production from the following: the Ordovician Ellenburger; the Pennsylvanian Morrow (gas), Atoka (oil and gas), and Strawn (reef oil) intervals; the Wolfcamp (gas) and Bone Spring (oil) formations of lowermost Permian; the Permian Yates (800-3500 ft deep), Queen, and Seven Rivers Formations; and the Delaware Mountain Group (4700-5200 ft deep). Structure contour maps demonstrate favorable Bone Spring conditions north of the WIPP site and the centrally located Delaware targets, as well as important Morrow development in the southern part. Five prospects are explored, and two are especially promising. Five anticlinal trends in this 12-township area bear field names as a result of production: Big Eddy, South Salt Lake, Cabin Lake, Los Medanos, and Sand Dunes. The Department of Energy's WIPP project is a planned repository for nuclear waste; despite centering on a deep dry hole, it occurs just northeast of productive Morrow formation. Whereas the successful tests seem concentrated on the structural highs, significant wells produce offtrend; the WIPP more » site lies in a syncline. « less

Production Technology Experience in Michigan Waterfloods

Summary Waterflooding started in the Niagaran carbonate reef oil reservoirs in northern Michigan in 1978 with Shell Oil Co.'s Chester 18 waterflood. Ten waterflood projects had been installed by Spring 1983. As a result of this experience, significant production technology practices have become established. The majority of the waterflood experience has been in Shell's Gaylord Production Unit located primarily in Otsego and Crawford counties. Specifically, the projects discussed are the Chester 18, Chester 21, Frederic 10, Hayes 15, Hayes 21A, and Mid-Charlton 10 waterfloods. In general, the waterflood program can be characterized by (1) very favorable oil program can be characterized by (1) very favorable oil production response, (2) timely and definitive production response, (2) timely and definitive surveillance techniques, (3) systematic and timely well work on injectors and producers to maintain optimum reservoir withdrawal behavior, (4) innovative application of artificial lift technology, and (5) aggressive future planning to maintain and to improve oil production response. planning to maintain and to improve oil production response. This paper elaborates on these waterflood program characterizations as follows.The favorable impact that waterfloods have had on oil production is discussed.The frequency and type of surveillance techniques are described for both injectors and producers. Some of the major techniques are pressure transient analysis, inflow performance plots, produced water cut and water weight records, injection and produced fluid analysis, hydrogen sulfide monitoring, reservoir withdrawal calculations, injection profile surveys, and well-to-well radioactive tracers.As a result of the surveillance techniques, well treatments have been designed for salt, calcium carbonate scale, gypsum scale, paraffin, and bacterial wellbore impairment. Surveillance has also resulted in continuous chemical injection programs to combat corrosion, scale, salt, oil/water reverse emulsions, bacterial formation, and H, S formation. The constant calculation of reservoir withdrawals has led to alterations in the various project operating policies.Withdrawal surveillance, inflow performance monitoring, and reservoir simulation have indicated that greater ultimate recovery, maximum operating income, and maximum present value profit will be achieved in spite of increasing volumes of water with high fluid withdrawals. Recent improvements in submersible pump technology (rotary gas separator and variable speed control) have enabled high withdrawal rates to be achieved efficiently (3,000 to 4,000 B/D [477 to 636 m'/d] fluid).An aggressive program for future activity has necessitated considerable short- and tong-term planning. Items such as facility sizing, disposal zone testing, produced water handling, electric power supply for northern produced water handling, electric power supply for northern Michigan, and source water development are some of the major items that have been studied. Introduction Waterflooding was initiated in a Niagaran carbonate reef oil reservoir in northern Michigan in 1978. Ten projects throughout the reef trend had been installed by Spring 1983. As a result of this experience, effective production technology practices have become established. This paper reviews the major production technology paper reviews the major production technology surveillance techniques and highlights some of the results. The Silurian Niagaran reefs, in which there are 600 separate fields, are located along the northern rim of the Michigan basin. Fig. 1 shows the reef trend with the locations of the five major waterflood projects. The reservoir consists of dolomite and limestone rock of the Silurian Niagaran reef and the overlying A-1 carbonate. The reservoir seal is an anhydrite bed called the A-2 evaporite. A more complete description of the carbonate reef geology is offered by Huh et al. A recent discussion of the total Niagaran reef play is given by Aminian et al. The size of the Niagaran reefs under waterflood range from 50 to 560 acres [202 344 to 2 266 249 m2 ]. The smallest has only two wells, whereas the largest has 20 wells. The design and operating programs initially planned for the waterflood projects have proved planned for the waterflood projects have proved successful. The operating data from the more mature projects have enabled development of effective production projects have enabled development of effective production technology practices. The projects discussed specifically are the Chester 18, Chester 21, Frederic 10, Hayes 15, Hayes 21A, and the Mid-Charlton 10 waterfloods that are operated by Shell Oil Co. in Otsego and Crawford counties. This paper reviewsthe favorable effect waterflooding has had on oil production;the frequency and type of production surveillance techniques;the results of some of these techniques;artificial lift considerations; andfuture planning of more waterflooding in the northern Michigan reef trend. Effect of Waterflooding on Oil Production Waterflooding has substantially increased oil production in the past 3 years. JPT P. 1446

Oil and Gas Developments in Western Canada in 1982

In 1982, petroleum industry activity in western Canada continued to decline as a result of economic recession, dropping oil and gas prices, high interest rates, and a worldwide oil surplus. Many smaller companies disappeared, and staff cuts were common throughout the industry. The total number of wells drilled dropped 9% to 6,285. Exploratory drilling decreased by 26% to 2,288 wells, whereas development drilling increased 4% to 3,997 wells. The exploratory success rate increased from 62 to 65% in 1982, with 761 oil discoveries and 732 gas discoveries. The development success rate increased slightly from 88 to 89%, with 1,742 oil completions and 1,823 gas completions. A late surge in drilling resulted from provincial and federal incentive programs designed to stimulate act vity. Average well depth decreased in all areas, and total revenue from land sales continued to plummet. Alberta land sale bonuses totaled $334 million(FOOTNOTE 4), British Columbia $17 million, Saskatchewan $34 million, and Manitoba $1 million. Average price paid per hectare dropped substantially in the 3 westernmost provinces, but increased by 75% in Manitoba. Number of hectares for sale declined in all areas. Downward exploratory drilling trends, which began in 1981, were accentuated in 1982. Alberta, Saskatchewan, and British Columbia activity dropped markedly, but Manitoba activity more than doubled. In Alberta, drilling was more cautious, with increased development drilling and fewer dry holes. A significant Devonian pinnacle reef oil discovery was made by Gulf Canada in the Fenn-Big Valley-Rumsey area, and major activity continued to be concentrated in the Peace River arch, Shekilie, and West Pembina areas. The $13.5 billion Alsands project was canceled. No discoveries of major significance were made in either British Columbia or Saskatchewan. Manitoba activity continued to soar for the third consecutive year as a result of the 1980 Jurassic oil discovery at Waskada. In the Arctic Islands, a major stepout oil discovery was made at Cisco, off Lougheed Island, and gas was discovered at Sculpin, near Ellef Ringnes Island. Beaufort Sea stepout oil discoveries were made at West Atkinson and Tarsiut. Delineation drilling on the Tarsiut structure has been disappointing and estimated reserves are less than anticipated. Future major exploration activity in the Beaufort Sea will continue as a result of several large farmouts by Esso and Gulf to Canadian consortiums. Esso also has a major development drilling project in the old Norman Wells oil field astride the Mackenzie River. The year 1982 was a pronounced continuation of 1981, with exploration interest shifting from the provinces to the northern and eastern frontiers. Within the provinces, drilling shifted markedly to oil plays, because of the depressed gas market, while expenditures were down significantly. The downturn in exploration appears to have ended, in part due to provincial drilling incentives, but no major improvement in activity is predicted for 1983.

Facies and Porosity Distribution, Swan Hills Reef Complex, Snipe Lake Oil Field, Alberta, Canada: ABSTRACT

All of the 11,700 ft (3,566 m) of core in this 130-well limestone reef oil pool was logged for a proposed miscible flood enhanced recovery scheme. The textures, fauna, porosity types, cements, and exposure surfaces are well preserved. Selected examples of each are presented by colored slides. Nine sedimentary facies and eight porosity types are noted. The porosity is facies selective, but is modified by solution and cementation. Submarine, blocky calcite cement is common. Vadose pendular cement is developed beneath some exposure surfaces. Twelve lithofacies, based on texture, fauna, color, porosity, and stratigraphic position are recognized. In the lagoons, poorly connected thin beds of porosity are present, whereas the reef flank porosity is relatively thick and contiguous. Three major depositional cycles, each about 40 ft (12 m) thick, are interpreted. The first terminated with subaerial exposure and local erosional truncation. A few inches of green shale formed in the lagoon. The second cycle began with a major transgression characterized by dense dark brown laminar strom bindstone containing brachiopods, corals, and crinoids. A shallowing-upward gradation to porous massive and branching strom framestone followed. A second exposure surface, capped by discontinuous green shale, marks the termination of this cycle. The third cycle is predominantly biostromal, thickening gradually to the southwest into thin-bedded lagoonal sediments. Local well-washed rudstones suggest beach environments. Stylolites are common in the lagoonal areas, and less numerous toward the reef front. Fractures are poorly developed and have only sparse porosity. Examples of porous stylolites and fractures from the nearby Goose River reef complex are shown. End_of_Article - Last_Page 564------------

Production Analysis in Exploration: Stettler Field Extension, Alberta: ABSTRACT

In October 1977, a significant extension to the 50,000,000 bbl Stettler D-3 and D-2 reef oil field was made 28 years after the initial 1949 discovery and 17 years after the field was considered fully delineated by exploratory and development drilling. The Stettler field is among a number of well-documented Upper Devonian reef fields and was seismically and geologically mapped before and after discovery. The potential of some Alberta reef field extensions became evident with the new oil economic reality following the Arab oil embargo of 1973. Attention was given to the structurally downdip, southwest closing rim of the Stettler dolomitized D-3 atoll during 1977-79 by the drilling of seven successful oil wells beginning with the Geneva Resources 6-17-38-20 W4 test on a prospect created by the speaker. From November 1977 to January 1, 1981, 122,869 bbl of crude were produced from the 6-17 well at an average rate of 108 bbl oil/day during that period. At least 1,000,000 additional barrels of primary Stettler oil will be produced as a result of these recent extension wells. The key to this successful prospect was the lead derived from using computer lists and decline curves of production data. By 1977, over 400,000 bbl of oil and less than 20,000 bbl of salt water had been produced from the 1960 Tenneco CPR 12-17-38-20 W4 well. This location was believed by industry in 1960 to have been close to the D-3 reef oil/water contact with an expectation of high water and low oil productivity. This example of a significant reef extension is a reminder that abundant, economic oil reserves remain to be discovered in other areas by a more realistic use of geology and production information available in existing computer files. End_of_Article - Last_Page 558------------

Depths of Oil Origin and Primary Migration: a Review and Critique

Vast amounts of geologic and geochemical data bearing on depths of oil origin and primary migration have been published during the past 30 years. Although concepts and understanding have evolved substantially, contrasting views also have been reinforced. Serious obstacles exist to theories of shallow in-place origin of reef oil and tar-sand oil. In reefs, environmental conditions would have dissipated and widely disseminated most of the organic matter. In sands, humic material could have accumulated abundantly, but its transformation to enormous quantities of heavy oil under the thin overburden characteristic of most tar-sand diagenesis is difficult to explain chemically. Investigations of a variety of modern sediments demonstrate: (1) sparsity of liquid hydrocarbons and free hydrocarbon precursors; (2) absence or traces only of many hydrocarbon and other bitumen components which are common in ancient rocks and crude oil; (3) dilute occurrence of dissolved organic matter and only traces of liquid hydrocarbons in interstitial waters; and (4) major upward movement of water to the surface, representing a serious loss to proposed shallow primary migration mechanisms. Experimental evidence indicates that effective barriers to mobility of liquid hydrocarbons and hydrocarbon precursors exist in source-type sediments under shallow burial. If hydrocarbons are in oil form, they apparently are immobilized by capillary attraction. In either oil or more finely divided occurrences, hydrocarbons are attracted to the bulk organic matter, which in turn is attracted to clays and other minerals. Hydrocarbon precursors in bitumen are subject to both organic and mineral barriers. At shallow depths, catalytic processes appear inadequate to explain any really significant hydrocarbon formation and primary migration. It is concluded that most crude oil and its constituents resulted from thermocatalytic transformations and primary migration at depths ranging from a few thousand to about 10,000 ft. Chemical alteration of organic matter should be greatly accelerated in the relatively high temperature-pressure regime at these depths. Energy input from heat and pressure should greatly increase the mobility of bitumen constituents formed, including hydrocarbons. Sufficient water should be available as a migration medium where expandable clays are abundant. Clay mineral transformation should release water and organic matter, and improve source-bed drainage. Large amounts of colloid-forming substances would be produced, and gases would be abundant products of organic alterations. Primary migration of liqu d hydrocarbons in colloidal, true-water, and/or gas solution would obviate the high-permeability requirements of migration in the form of oil. Thermal investigations of oil shale and disseminated kerogen show that the heavy nonhydrocarbon part of the bitumen is produced initially, and at higher temperatures the bitumen is altered in part to hydrocarbons. The fact that relatively high temperatures are needed for these transformations, even in the presence of catalysts, argues for rather deep corresponding transformations in the sedimentary section. Bitumen contains colloid-forming fractions which would greatly increase the solubility of hydrocarbons in water. Carboxylated (colloid-forming) organic material is relatively resistant to temperature increase in a water-wet environment, even where catalysts (clays) are present. Hence colloids should remain active to considerable depth. Laboratory experiments indicate that thermocat lytic processes can best explain the origin of liquid normal paraffin hydrocarbons of oil from carboxylated organic matter. Several studies of depth patterns in nonreservoir (source type) rocks of the geologic section reveal that both bitumen and the hydrocarbon component of bitumen increase markedly in the depth range of a few thousand to several thousand feet. The increase in hydrocarbon abundance is particularly impressive. In some examples, a zone of sharply decreasing bitumen and hydrocarbon occurrence has been observed directly below the zone of abundance, indicating that primary migration has evidently taken place. Much primary migration apparently is related to stages of dehydration of expanded clay minerals, the most important stage being temperature-dependent. Coordinated studies of geology, geochemistry, and oil occurrence, particularly in the Soviet Union and northwestern Germany, support major origin-primary migration episodes at depths of a few thousand to several thousand feet or more. They also suggest continuous or recurrent primary migration through rather long time and broad depth intervals. Ultra-deep origin of mobile oil, and upward migration through thousands of feet of shale are shown to be very unlikely. In examples such as the South Sumatra, Los Angeles, and Ventura basins, where the ultra-deep concept has been applied, the data can be explained better by primary migration at intermediate depths.

The great barrier reef conservation issue—A case history

In the last decade there has been increasing industrial and political pressure for the development of the resources of the Great Barrier Reef, Australia. As a result, conservation of the Reef is now probably one of the most important social and political issues in Australia. A strong conservation movement has developed which prevented the mining of a section of the Reef for lime. Additionally, after a national controversy, inquiries into both the development of a Reef oil industry and the damage caused by the Crown-of-thorns Starfish, have been instituted.

Upper Devonian Reef Oil Field--Redwater, Alberta, Canada: ABSTRACT

The Redwater oil field discovered in 1948 has inplace reserves of 1,300 million bbl, about 64 percent of which will be recovered. The field is a single pool 58 sq mi in area along the updip edge of a large Late Devonian (Frasnian) limestone reef complex. The complex is more than 800 ft thick, roughly triangular in plan and about 225 sq mi in area. More than 900 wells have been drilled in the field area where normal forereef, reef, and backreef facies are recognized. Porosity and permeability were influenced by diagenesis, but conform with the primary facies patterns. The Redwater reef grew during a major subcycle within the Kaskaskian sequence. Transgression over shoal carbonate of the previous subcycle created a End_Page 529------------------------------ reef-prone shelf of moderate depth. The reef was enveloped by clayey and carbonate muds which prograded across the shelf. Nearly 3,000 million bbl of recoverable oil in Redwater and nine companion reefs attests to favorable trap-to-source relations in this basin setting. Recognition of reef-prone cycles of deposition and early understanding of the depositional/tectonic framework which affects reef distribution are important in guiding exploration for Redwater-like reefs in new areas. Local, less predictable factors can influence the effectiveness of the reefs as traps and the success of exploration. Subsequent basin history is critical, for depth of burial affects the feasibility of seismic exploration and imposes regional eometamorphic patterns of hydrocarbon distribution. End_of_Article - Last_Page 530------------