Reef Trend Research Articles

Dolomitization and Late Secondary Porosity Development in Nisku Reefs (Late Devonian) of Alberta: ABSTRACT

Dolomitization and associated calcite dissolution are important controls on reservoir quality in coral reefs of the Nisku Formation. Average porosities of 13 to 15% and permeabilities of 3 darcys are recorded in the fully dolomitized reefs, while lower average porosities of 3 to 5% and permeabilities of 350 milli-darcys are recorded in partly dolomitized reefs. The close correlation between dolomites and high porosity and permeability is best understood by examining the paragenetic sequence and spatial distribution of the dolomites. Dolomitization occurred over a long period of burial and resulted in the formation of two major types of dolomites that are volumetrically significant. The first is characterized by matrix-selective, gray, cloudy, 20 to 150-µ crystals that grade from scattered subhedral and euhedral rhombs to interlocking crystalline mosaics. Matrix dolomites are slightly calcitic (51 to 53 mole % Ca), have a low iron content (less than 0.04 oxide wt. %), show a pronounced fabric selectivity toward micrite, and are abundant in all of the reefs. The second major type of dolomite is characterized by pervasive, brown, cloudy, 60 to 300-µ crystals that occur in the flanks of structurally updip reefs and throughout the downdip reefs. The pervasive dolomite exhibits similar chemical characteristic to the matrix dolomite and in some places replaces it. Concentration of dolomite crystals and dissolution of individual rombs along stylolites indicate that the matrix dolomite initially formed at shallow depths. As dolomitization progressed, dolomite recrystallization and cementation along with extensive calcite dissolution resulted in dramatic increases in porosity and permeability. Calcite dissolution continued after dolomitization ceased, but much of the dissolution is coeval with dolomitization. Evidence for the coeval relationship includes a complete gradation from partly dolomitized corals with dissolution of parts of the calcite skeleton to totally dolomitized rock with biomoldic porosity. Dolomite overgrowths, some of which are enriched in iron (up to 1.5 oxide wt. %), formed during progressive burial. Dolomite cements commonly e tend into tension fractures that displace and are displaced by stylolites, indicating formation at greater depths than the precursor crystals. Matrix and pervasive dolomites exhibit values for 18O from -2.5 to -6.0^pmil PDB and 13C from +2.5 to +6.0^pmil PDB. The negative shift of 18O values from those of modern dolomites formed at shallow depths may be the result of formation at elevated burial temperatures. Pervasive dolomites are the result of recrystallization of the matrix dolomite and possibly primary dolomitization of the reef-flank facies. Isotopic data support a strongly rock-buffered system. Late dolomites and secondary porosity in the Nisku reef trend increase in abundance down structural dip, toward the southwest. Thus, much of the dolomite and late porosity is post-Devonian and probably formed during the late Paleozoic and early Mesozoic when the regional structure tilted to the southwest. Although all Nisku reefs form stratigraphic traps, late diagenetic overprints in some significantly enhanced their reservoir quality. End_of_Article - Last_Page 412------------

Subsurface Glen Rose Reef Trend in East Texas and West-Central Louisiana: ABSTRACT

The subsurface Glen Rose trend in east Texas and west central Louisiana (Lower Cretaceous Comanchean) is a regressive carbonate complex deposited on a broad shallow water shelf. The major structural influences on deposition were the East Texas basin and the northwest Louisiana basin, separated by the Sabine uplift. The Glen Rose trend can be differentiated into two separate reef tracts that prograded seaward over a slowly subsiding shelf. The Upper and Middle tracts overlap within the East Texas embayment and diverge over the southern flank of the Sabine uplift eastward into Louisiana. The trend appears to be located midway between the shoreline and shelf edge. It remains to be seen whether the Glen Rose are actual framework reefs or mounds of transported material. Cores through the massive limestones reveal porous buildups of varying compositions. Reef facies include poorly sorted caprinid-coral grainstones, moderately sorted peloid and oncolite packstones and grainstones, and well-sorted, very fine grained skeletal grainstones. Coated grains, abraded skeletal fragments, scoured bedding surfaces, and minor cross-beds are evidence for deposition of the facies in a high-energy shoal setting. The reefal buildups grade laterally into low-energy shallow water wackestones and mudstones containing toucasids, orbitolinids, and serpulid burrows. Porosities associated with the reefal buildups appear facies controlled. Caprinid-coral packstones and grainstones exhibit intraparticle, moldic, and vuggy porosities of 10 to 15%. Pinpoint End_Page 410------------------------------ microporosity of 5 to 10% are found within the finegrained skeletal grainstones. Fracture porosity enhances permeability in several facies. Moldic and vuggy porosity types are generally secondary whereas intraparticle porosity may be preserved primary. Pinpoint microporosity is probably matrix related secondary porosity. Coarse equant calcite commonly occludes intraparticle, moldic, vuggy, and fracture porosities. Dolomitization within the reef limestones may have acted to create or preserve porosities. Poor production from the Glen Rose trend has been attributed to the lack of structural closure. Use of all available electric logs and sample logs in conjunction with extensive core and thin section analysis should provide new insight on carbonate diagenesis and the relationship to porosity-permeability trends within the Glen Rose trend. End_of_Article - Last_Page 411------------

Outcrop-to-Basin Stratigraphy and Structure of Glen Rose Limestone of Central Texas: ABSTRACT

The Glen Rose Limestone is a proven oil and gas producer in south Texas along the Stuart City reef trend. However, it has not been productive, except in minor occurrences, in the East Texas basin, even though it is present in an area of approximately 75,000 mi2 (195,00 km2) and attains a maximum thickness of 3,500 ft (1,067 m). This absence of production is believed to result from a lack of exploration rather than a lack of potential. Therefore, a regional study of the outcrop-to-basin stratigraphy and structure of the Glen Rose in central Texas was undertaken to correlate existing stratigraphic nomenclature and to determine the depositional and diagenetic history. Be relating these to known production, it should be possible to identify potential exp oration fairways. Cross sections were used in establishing stratigraphic correlations, resulting in a division of the Trinity Group different from that commonly seen in literature. The group is divided into the Glen Rose and Travis Peak subgroups, with the division at the outcrop placed at the Hensel-lower Glen Rose contact. However, in the basin, the Pearsall-Rodessa contact is used as it is time-equivalent to the division adopted at the outcrop. Examination of cores, cuttings, and sample logs defined the depositional and diagenetic environments of Glen Rose strata. Isopach maps and seismic sections were used to map distribution of facies tracts related to production. Facies and structure of known production areas were compared to those of untested areas to define possible exploration fairways and to map recommended exploration trends. Principal of these is the Stuart City reef trend. End_of_Article - Last_Page 548------------

Burial Cements in Lower Cretaceous Pearsall Formation and Lower Glen Rose Formation, South Texas: ABSTRACT

Lower Cretaceous platform carbonates and shales were buried to depths in excess of 2,000 ft (610 m) by the end of Eocene time, and were locally affected by late-stage cementation. Burial diagenetic cements include ferroan baroque dolomite, ferroan and nonferroan calcite, anhydrite, kaolinite, barytocelestite, galena, and sphalerite. The lack of these minerals in outcrop and their occurrence in fractures are evidence for a subsurface origin. Carbonate cements are chemically and isotopically zoned; the FeCO3 content in baroque dolomite cement varies by as much as 10 wt. % across a single crystal. Stratigraphic and regional distribution of iron in baroque dolomite indicates that the iron is derived from local sources. Good negative correlation between ^dgr13C values and iron contents of baroque dolomite suggests the End_Page 572------------------------------ simultaneous reduction of iron oxides and oxidation of organic material. Some of the late subsurface carbonate cements with extremely depleted ^dgr18O values precipitated either from hot brine or from isotopically light water; both possibilities require the vertical movement of fluid along faults. Galena and sphalerite occur in small amounts in some cores; a single fluid inclusion homogenization temperature from sphalerite was 20°C (68°F) higher than the present formation temperature at that depth. Brines moving up faults after albitizing feldspars in more deeply buried formations could be the source of lead and zinc for these minerals. Strontium isotopic ratios for calcite cement in these rocks are similar to ratios for brines from the Stuart City reef trend that are believed to originate deep in the Gulf of Mexico basin. End_of_Article - Last_Page 573------------

Potential Oil Corridor Bisects Australian Continent: ABSTRACT

New oil discoveries, coupled with intensified exploration in the past four years, suggest that several of Australia's major onshore basins can be linked to form a potential oil corridor which will span the continent. The huge Canning basin forms the western part of the corridor and lies adjacent to fields in the Amadeus and Pedirka basins in central Australia which merge with the oil provinces of the central Eromanga and Cooper basins which are linked, in turn, to the eastern Surat basin. Some narrow basement arches separate and form the only barriers to a zone which crosses the Great Inland deserts of the continent. Eventually this zone could support a network of pipelines and other facilities to provide the infrastructure required for easier economic development of remo e outback regions. Parts of the infrastructure are now being developed or already exist such as the pipelines from Moomba to Sydney and Adelaide. As new oil discoveries, such as those at Blina in the Canning basin and in Jackson in the Eromanga basin, are made, this infrastructure will grow along the potential corridor and away from it to coastal waters. The corridor owes its origin in the main part to the geometry of ancient basic tectonics and subsequent sedimentation patterns. For instance, Ordovician oil-rich sequences linked the Canning and Amadeus basins, whereas Jurassic oil reservoirs cross the remainder of the eastern half of the corridor. Potential new discoveries are predicted for sequences which range in age from upper Proterozic to Neocomian and these can be reviewed within he corridor. Devonian reef trends flank the northern Canning End_Page 440------------------------------ Figure basin while Ordovician carbonates and shales form potential fields throughout parts of the southern Canning basin. Thick sequences of interbedded clastics and marine rocks of Silurian to Permian age form additional targets in several depocenters in the Canning. Oil reservoirs of Ordovician age occur in the western Amadeus basin but new plays exist in the basal Cambrian sands of the eastern Amadeus and potentially in the northern thrust sheet belt. Oil has now been found in rocks of Permian, Triassic, Jurassic, and Cretaceous age in the Cooper-Eromanga basin. New plays exist with the extensions of the central Eromanga basin where higher heat flow and deeper burial has matured younger Jurassic sources. The more established Surat basin has further potential in Permian and Triassic rocks s does the Mesozoic in the coastal Clarence-Moreton and Sydney basins. With less than 200 wildcats being drilled every year, the potential for this corridor certainly lies in the future. End_of_Article - Last_Page 441------------

Diagenetic Components Within Woodbine Formation, East Texas: ABSTRACT

The Upper Cretaceous Woodbine Formation contains diagenetic components in the form of cements and clays which can cause problems in drilling, completing, and stimulating a well. These diagenetic components are present in pore systems of the rocks deposited within various Woodbine depositional systems ranging from fluvial to deep marine. Fluvial environments were present in the northeast area of the East Texas basin, and changed to deltaic-marine systems to the south and southwest. Deeper marine sediments are represented by a thickening clastic wedge deposited over the Edwards reef trend as channels, interchannels, and submarine fans. It is necessary to identify mineral types, crystal morphologies, and modes of occurrence of the diagenetic components within pore systems of rocks formed in these various depositional settings so that proper drilling, completing, stimulating, and/or acidizing programs can be conducted. Calcite, dolomite, ankerite, and quartz are important cements which reduce porosity and affect reservoir quality of the Woodbine Formation. Carbonate minerals occur as isolated patches or extensive cement within the intergranular network. Quartz cement is commonly observed in the form of euhedral overgrowths. The storage capacity of the reservoir and productivity of a well can be hindered where these cements reduce and isolate primary and secondary pores. During completion, stimulation, and possibly acidization, calcite may cause further problems through reaction with hydrofluoric acid and precipitation of formation-damaging calcium fluoride. Iron hydroxide precipitates may also form when iron-rich calcite, dolomite, and ankerite are contacted by HCl, HF, and HCl/HF acids. These preci itated gels can block pores and reduce production. Important clay components found within the pore network of the Woodbine Formation are kaolinite and chlorite. Kaolinite commonly displays a pseudohexagonal book and platelet morphology. It is relatively stable with respect to acids; therefore, acidization should have minimal effect on the kaolinite. A problem of migration of fine particles can arise when these books and platelets are loosened from framework grain surfaces. Turbulence within pore networks, caused by fluid movement during stimulation and production, especially near the wellbore or a fracture face, can cause the kaolinite fines to move and block pore throats. This could result in formation damage. Chlorite occurs as well to moderately crystalline platelets which reduce porosity by lining and filling pore areas. If th chlorite, is iron-rich and contacted by HCl, HF, and HCl/HF acids, a problem of iron hydroxide precipitation can occur. Other clays within the Woodbine Formation include illite and smectite. Authigenic illite is found as incipient growths on chlorite platelets. The smectite has a honeycomb morphology and occurs as a grain coating. These components can cause problems if present in significant amounts within Woodbine reservoirs. If relatively fresh water is allowed to contact the formation, illite can mush and the smectite can swell, both damaging the formation. Drilling, completing, stimulating, and acidizing programs can End_Page 562------------------------------ be designed to minimize problems caused by diagenetic components. Well production can even be increased when proper procedures are designed using information on potential formation damaging diagenetic minerals that are present within pore systems of Woodbine reservoir rocks. End_of_Article - Last_Page 563------------

Growth Faults and Salt Tectonics in Houston Diapir Province--Relative Timing and Exploration Significance: ABSTRACT

ABSTRACT Oil and gas accumulation in Gulf Coast Tertiary strata is mainly controlled by regional growth faults and by salt-related structures. Salt forms the most prominent set of structures in the Houston diapir province of southeast Texas. Recent work in three study areas shows that the Tertiary growth-fault trends so well displayed along strike to the southwest continue through this salt basin as well, but have been deformed by later salt movement. In the Katy area, seismic data disclose early (pre-Wilcox) salt pillows downdip of the Cretaceous reef trend. Progradation of the lower Wilcox Rockdale delta system created a linear growth-fault trend above and seaward of the pillows. Salt stocks were injected upward from the pillows in Claiborne time and were flanked by deep withdrawal basins and turtle structures. Major oil accumulations occur over an inferred turtle structure and over deep-seated salt domes. The lower Wilcox growth-fault trend deformed by the later salt flowage is virtually unexplored, although geopressured gas production from these low-permeability deltaic reservoirs exists in adjacent areas. In Brazoria County, a major lower Frio growth-fault trend affecting the Houston delta system was deformed by later salt domes, by a salt-withdrawal basin, and by a possible turtle structure at Chocolate Bayou. A productive geopressured aquifer exists in the salt-withdrawal basin bounded by the previously formed growth faults. In Jefferson County, in contrast, salt tectonic activity and growth faulting appear to have been coeval. Early salt-cored ridges continued to rise throughout Frio deposition; growth faults occur both updip and downdip. Salt diapirism may have occurred throughout Frio time at Orange and Port Neches salt domes, but other domes such as Spindletop formed in post-Frio time. Hydrocarbons accumulated over the salt domes in growth-fault anticlines and in stratigraphic traps. Contemporaneous, low-intensity growth faulting and salt movement may be ascribed to the minimal loading imposed by the sand-poor lower and middle Frio section. Recognition that shelf-margin growth faulting preceded the development of the present pattern of domes and basins has important implication for hydrocarbon exploration. Growth faults may be migration paths for hydrocarbons; furthermore, early-formed traps, distorted by salt movement, may still be found to contain hydrocarbons. Figure 1. Regional shelf-margin trends of the Gulf Coast Basin and location of the Katy, Pleasant Bayou, and Port Arthur study areas. Map from Winker and Edwards (1983). End_Page 83-------------------------

Exploration and Development--Gulf Coast Mesozoic, 1982 and 1983: ABSTRACT

Looking at exploration and development within the Gulf Coast Mesozoic region as a whole, the trend has been toward shallow oil and away from deep gas. The capability of each area to successfully accommodate this shift is dramatically reflected in the comparison of total wells drilled in 1982 as compared to 1981: Table The southeastern states were hard hit because this area was so strongly oriented toward deep Hosston and Cotton Valley gas plays, and there were no viable shallow oil plays available as quick alternatives. South Arkansas and north Louisiana suffered some from the downturn in Smackover and Cotton Valley exploration (note total wells much greater than in the southeastern states), but there were numerous plays to be made in the Upper Cretaceous Sands, Wash.-Fred., Paluxy, Rodessa, Sligo, and Hosston. East Texas actually faired better in 1982 than 1981, in part because of the many shallow oil plays to be made, but also because, according to G.C.S. statistics, the shift to shallow oil had actually begun between 1980 and 1981, so momentum in this direction was already present. South Texas s w the demise of the Austin Chalk play within the Giddings trend through Lee and Fayette Counties. Nevertheless, the Chalk play remains active in Atascosa and Wilson Counties. The most significant trends in the southeastern states during 1982 were the Rodessa-Cotton Valley play centered in Warren and Hinds Counties, Mississippi, and the Miocene play of Baldwin and Mobile Counties, Alabama. The most significant discovery was the Movico Smackover field on the west flank of the Mobile graben in Mobile County, Alabama. In 1983, an apparent major Smackover discovery has been made by Beau Coupe Oil & Gas in extreme southeastern Escambia County, Alabama. Also, there is an important play developing in the lower Tuscaloosa on the shelf slope between the low relief anticlines of northwestern Mississippi and the Tuscaloosa growth faults of southern Louisiana. Although exploration in north Louisiana and south Arkansas was relatively strong, most activity was concentrated in or around existing fields. The west and north flanks of the Pine Island dome located in Caddo Parish, Louisiana, were the sites of very intense activity. Exploration and development are directed toward the Sligo with secondary pays in the Rodessa and Hosston. In all, 44 wells have been drilled to these pays in and around the shallow Pine Island Pettit oil field. East Texas activity was dominated by discoveries and development of Rodessa and Pettit fields in the basin and on the west and south flanks of the Sabine uplift. However, the most significant discovery last year was the East Ginger Smackover field in Rains County. In early 1983, Cities Service made headlines with what appeared to be a major discovery in eastern Cass County. A 40-ft (12-m) pre-Smackover sand made a strong flow of oil and gas before going to water. As 1982 came to a close, it appeared that south Texas would have an important play in the Sligo, seaward of the Stuart City Reef trend. However, at this time, commercial production from the Sligo has not been established definitely. End_of_Article - Last_Page 1474------------

Small-Diameter Concentric Tubing Extends Economic Life of High Water/Sour Gas Edwards Producers

Introduction The Edwards reef trend extends from the Buchel area in DeWitt County, TX, to the Mexican border. Tight, relatively thin sour gas objectives are underlain by water sources, which may be encountered unintentionally during hydraulic stimulation. Erratic, rapidly declining production with associated water, coupled with increased operating costs, resulted in decreasing financial returns. Subsequent installation of small-diameter concentric tubing has enabled continuous productivity as well as provided an inexpensive means of corrosion inhibition. This has extended economic productivity in two fields along the Edwards trend. Development drilling of the Edwards limestone in the West Cooke and West Stuart City fields, LaSalle County, TX, was begun during 1976 (Fig. 1). Completions are at an average depth of 10,000 ft (3050 m). Porosities range up to 10%, although 5 to 6% or less is more common. Permeabilities may average about 0.1 md; however, they are more frequently less than 0.01 md, with rare streaks as high as 10 md. With such low-order permeability and porosity, stimulation for an extended distance from the wellbore is essential to establish any sustained productivity. For the most part, this has entailed hydraulic sand fracture treatments; although only acidizing, at pressures exceeding fracture gradients, has effected production in some cases. All fracture treatments were down 5 1/2-in. (14-cm) casing, with up to 400,000 gal (15 140 m3) water-base fluids. In anticipation of high flow rates, 2 7/8-in. (7-cm) production tubing then was installed. Postfracture monitor surveys indicated some vertical fracture extensions as much as 50 ft (15 m) beyond the perforated intervals for possible contact with adjacent water sources. Later, density-controlled well stimulation was effective in establishing economical gas flow without a significant initial increase in water production.1 Prefracture injection surveys might have resulted in more successful fracture treatments.2 Unfortunately, with pressure depletion, water recovery continued to increase to a point where sustained production could not be maintained for seven out of nine completions. Produced gas contains about 6% CO2 and up to 2% H2S. In view of the potential pollution attributable to venting this gas, only minimum flow tests were conducted initially. Thus, only nominal amounts of load and treatment fluids were recovered before completion of the plant treating facilities and gathering system. Gas sales began during July 1977. However, with rapid accumulation of water in the wellbore, four out of nine wells ceased flow during the first 3 months of sales. Liquid Loading Liquid accumulation tends to occur whenever produced water does not flow out of the wellbore at the same velocity as the gas.3,4,5 Displacement of corrosion inhibitors with water may magnify this problem. Bottomhole pressure (BHP) surveys verified that a full column of water would exceed the reservoir pressure. Fortunately, permeability of the induced fractures has been sufficiently high for the water to be ultimately displaced back from the wellbore, under static conditions as gas rises in the tubing, as a result of density segregation. By this means, it was possible to maintain some production by stopcocking. That is, the wells were flowed until the accumulated fluid head plus line pressure equaled the reservoir pressure and the well ceased flowing. After the well was shut-in for a day or so, and after ultimate displacement of the accumulated water from the tubing by gas migration, the shut-in wellhead pressure in some cases increased to +2,000 psi (14 Mpa) to enable further flow. By such stopcocking, erratic production was maintained. For maximum productivity by this means, the wells required close surveillance. In addition, it became necessary to displace the corrosion inhibitor each month with nitrogen to minimize shut-in periods.

Carbonate Sedimentation of Reef and Associated Shoal-Water Facies, Sligo Formation (Aptian), Black Lake Field, Natchitoches Parish, Louisiana: ABSTRACT

The Black Lake field is one of the larger Lower Cretaceous carbonate hydrocarbon reservoirs along the U.S. Gulf Coast. The field produces from the Pettet porosity zone of the upper Sligo Formation. This porous zone coincides with a variety of carbonate facies that were deposited on a wave-dominated shelf as caprinid reefs and associated shoal-water deposits. Distinctive associations of lithologies, textures, fabrics, structures, and faunas provided the basis for recognizing seven major carbonate lithofacies in the field. Lithofacies present in the field include (1) caprinid, (2) oncolite, (3) oolite, (4) bioclastic, (5) bioclastic micritic, (6) foraminiferal, and (7) micrite lithotypes. A sequence of lithofacies maps and stratigraphic cross sections describe the areal geometry, distribution, growth, and movement of the various major carbonate lithofacies within the field through a short span of geologic time. Sediments deposited under the caprinid reef in the field were predominantly foraminiferal and bioclastic lime mudstones and wackestones characterized by massive bedding, bioturbation, mollusk debris, and abundant remains of Orbitolina texana. Caprinids initially began flourishing in the northeastern part of the field as one distinct circular body surrounded by mud-supported sediments. The caprinid lithofacies migrated in a southwesterly direction, suggesting that the predominant movement of longshore currents was from the northeast to the southwest. The caprinid formed a distinct linear carbonate buildup that trended in a northeast-southwest direction. Bioclastic micritic and bioclastic sediments formed on the landward and seaward sides of the reef trend, respectively. This demonstrates the the reef acted as a local wave-resistant barrier or baffle that allowed muddier bioclastic wackestones to accumulate behind (landward) the caprinid reef trend. The cross-sectional geometry of the caprinid lithofacies along with the dominance of reef debris landward of the main reef axis suggests that the caprinid reef developed on a wave-dominated shelf. As the reef development continued, a landward shift in local energy levels occurred. Along with the shift of energy level, the position of the longshore current also moved landward. This allowed stronger cur ents to move behind the reef trend (landward) and form and deposit coarser-grained sediments. The elongate reef trend was severed presumably by longshore and tidal currents. The resultant buildups were separated by a sub-perpendicular trend that consisted of bioclastic sediments which most likely represented a tidal channel through the caprinid reef. Bioclastic micritic sediments accumulated on the lee side of the reef trend in current sheltered areas. Caprinid reef growth stabilized and shoal-water deposits began to develop on the landward side of the reef trend. These shoal-water deposits consist of oolite and oncolite shoals and bioclastic reef-flank sediments deposited laterally adjacent to the caprinid lithofacies. The shoal-water deposits continued to develop and prograded over the area formerly occupied by the caprinid reef trend. End_of_Article - Last_Page 601------------

Oil and Gas Developments in Michigan in 1981

The exploration for and development of Middle Silurian Niagaran reefs dominated Michigan's oil and gas industry activity for the 13th year in a row. Heaviest drilling was concentrated in the northern part of the Southern Peninsula along the reef trend. Reef exploration also continued at a high pace in south-central and southeastern Michigan. Overall, well completions in 1981 broke a 20-year record. Exploration resulted in 69 new discoveries, 84% of which were new Niagaran reef reservoirs. A gas discovery in the Prairie du Chien Group, at a depth greater than 10,000 ft, generated a great deal of excitement in the central basin deep play. Exploration and development footage figures, derived from Michigan Geological Survey Division records, amounted to 1,766,593 ft exploratory and 1,255,759 ft development compared with 1,375,993 ft exploratory and 1,468,038 ft development drilled in 1980. An additional 135,686 ft, mainly gas storage facility wells, is credited to 1981. Oil and gas production declined slightly in 1981. Preliminary figures show that Michigan produced 32,664,000 bbl of oil (including condensate) and 152,593 mcf of gas. Niagaran reef reservoirs located along the northern reef trend accounted for approximately 72% of the oil and 83% of the gas produced in 1981.

Reef Exploration in Michigan Basin: Problems and Solutions: ABSTRACT

The integration of all aspects of geology with geophysics is necessary in any stratigraphic exploration program. The Niagara (Middle Silurian) pinnacle reef play in the Michigan basin provides interesting insights into this multifaceted problem. The Michigan basin is an intracratonic structural basin which has been in existence at least 500 million years. During Niagaran time, tall (up to 700 ft, 213 m) hydrocarbon-bearing pinnacle reefs grew on a ramp or shelf between a deeper basinal area and a nonproductive basin-rimming barrier reef bank. These pinnacle reefs are encased in Salina (Upper Silurian) evaporites and carbonates that effectively act as both seal and source for the hydrocarbons. Geological studies of Niagara and Cayugan paleogeography and regional stratigraphy combined with detailed lithofacies have aided in the mapping of the pinnacle reef trends and the identification of local reef proximity indicators. Today, seismic data is the major exploration method for actually locating the pinnacle reefs, but major problems had to be overcome before it was an effective tool. Surface topographic features (such as glacial moraines and sand dunes) plus buried preglacial valleys caused severe statics, velocity, and problems. Judicious application of good basic data processing procedures with particular attention paid to statics corrections, velocity analyses tied to well control, and f-k filtering, commonly solve these data processing problems. Even though shooting geometry has been optimized to reduce noise, reflections are often the third or fourth strongest mode on a field record with mode converted shear waves, refractions, multiples, and wave-guided phenomena being stronger. F-k filtering, following the principle of reflection mode amplification (introduced herein), can substantially enhance the signal to noise ratio (reflection to nonreflection ratio). The variable distribution of the Salina evaporites and carbonates and their irregular solution margins can, however, in places, produce reeflike seismic anomalies. By careful geologic mapping with close attention to facies and lithologic detail and by using simple seismic modeling, the differences between pseudo-reef anomalies and actual reef anomalies can often be distinguished, and the presence of seismic reef proximity indicators can be confirmed with a high level of confidence. The 70% and greater wildcat success ratios maintained consistently by several companies which has allowed them to lead in the exploration of the trend are ample testimony to this. The final results of careful attention to geologic detail during the entire geophysical analysis, from field acquisition through interpretation, are not only accurate and detailed seismic stratigraphic interpretations, but also cost-effective exploration programs. End_of_Article - Last_Page 593------------

The origin and evolution of saline formation water, Lower Cretaceous carbonates, south-central Texas, U.S.A.

Systematic chemical variation exists in formation water collected from a dip section through Lower Cretaceous rocks of south-central Texas. Chemical variation can be explained by an interactive water-rock diagenetic model. The cyclic Lower Cretaceous shelf carbonates of the Edwards Group dip into the Gulf of Mexico Coast “geosyncline”, and can be considered, to a first approximation, as part of a complex aquifer contained by Paleozoic basement beneath, and by relatively impermeable Upper Cretaceous clay and chalk above. The hydrodynamic character of this carbonate system is strongly controlled by major fault systems. Major fault systems serve as pathways for vertical movement of basinal brines into the Lower Cretaceous section. Formation water movement in this sytem has strong upfault and updip components. The “parent” Na/1bCa/1bCl brine originates deep in the Gulf of Mexico basin, at temperatures between 200 and 250°C, by the reaction: halite + detrital plagioclase + quartz + water → albite + brine Other dissolved components originate by reaction of the fluid with the sedimentary phases, K-feldspar, calcite, dolomite, anhydrite, celestite, barite and fluorite. Significant quantities of Pb, Zn and Fe have been mobilized as well. As the brine moves updip out of the overpressured deep Gulf of Mexico basin, and encounters limestones of the Stuart City Reef Trend (the buried platform margin), small amounts of galena precipitate in late fractures. Continuing to rise upfault and updip, the brine becomes progressively diluted. On encountering significant quantities of dolomite in the backreef facies, the Ca-rich brine causes dedolomitization. Although thermochemical consideration suggests that small amounts of several authigenic phases should precipitate, most have yet to be found. Minor amounts of several kinds of calcite spar are present, however. As the brine evolves by dilution and by cooling, no systematic changes in any cation/Cl ratio occur, except for regular updip gain in Mg as a result of progressive dedolomitization. The formation water, highly diluted by meteoric water, eventually discharges along faults as hot mineral water.

Late Jurassic-early Cretaceous reef trends on the continental margin SW of the British Isles

Abstract: SUMMARY: Multichannel seismic reflection data has been used to outline the distribution of reefs or carbonate banks on the continental margin SW of the British Isles. This distribution is discussed in terms of regional structure and stratigraphy. All the reefal bodies are pre-Aptian in age, with evidence for both late Jurassic and early Cretaceous phases of reef development. Reef growth was contemporaneous with rifting prior to the occurrence of sea-floor spreading in the Bay of Biscay. The distribution of reefs suggests that shallow marine conditions persisted in the Goban Spur area until middle Cretaceous time, while a deeper embayment may have occupied the Bay of Biscay as early as the late Jurassic.

Origin and Evolution of Saline Formation Waters, Lower Cretaceous Carbonates, South-Central Texas: ABSTRACT

Systematic chemical variations exist in formation waters collected from a dip section through Lower Cretaceous rocks of south-central Texas. These chemical variations can be explained by an interactive water-rock diagenetic model. Cyclic Lower Cretaceous shelf carbonates of the Edwards Group that dip into the Gulf Coast geosyncline act as an aquifer contained by basement beneath, and relatively impermeable Upper Cretaceous clays and chalks above. The hydrodynamic character of this carbonate system is strongly controlled by major fault systems which serve as pathways for the vertical movement of brines into the Lower Cretaceous section. Formation-water movement in this system has strong updip and upfault components. The parent Na-Ca-Cl brine originates deep in the gulf basin, at temperatures between 200 and 250°C, by the reaction: halite + detrital plagiocalse + quartz + water ^rarr albite + brine. Other dissolved components originate by reaction of the fluid with the sedimentary phases, K-feldspar, calcite, dolomite, anhydrite, celestite, barite, and fluorite. Significant quantities of lead, zinc, and iron have been mobilized as well. As the brine moves updip out of the overpressured deep gulf basin, encountering limestones of the Stuart City reef trend (the buried platform margin), small amounts of galena precipitate in late fractures. Updip and up-fault, the brine becomes progressively diluted with downward-moving meteoric water. On encountering significant quantities of dolomite in the backreef facies, the Ca-rich brine causes dedolomitization. Although thermochemical considerations suggest that small amounts of several authigenic phases should precipitate, they have yet to be found, except for minor amounts of calcite spar. As the brine evolves by dilution cooling, no systematic changes in any cation/Cl ratio occur, except for regular updip gain in magnesium as a result of progressive dedolomitization. The high diluted formation water eventually discharges along faults as hot mineral water. End_of_Article - Last_Page 947------------

Hydrocarbon Exploration on Ancient Shelf-Slope Breaks: ABSTRACT

A general set of traps, reservoirs, and seals occurring on the shelf-slope break can be hypothesized based on the structural regime, provenance, and width and slope of the shelf. To evaluate this break is to look at the entire region--shelf and slope. With a wide or moderately wide shelf, gentle slope, and peneplaned provenance, carbonate sediments would dominate in marine environments. Logically, a reefal environment (reservoir) would be expected at the shelf slope. Conversely, with a narrow shelf and a positive continental borderland in close proximity, terrigenous clastics would be expected. Deltaic-like reservoirs could be expected on the shelf; turbidites would logically occur downslope. A broad shelf with a positive provenance could inspire various lithologic deposition (depending on the environment)--reefal at the shelf-slope area, deltaic or lagoonal behind, and turbidites in front. Examples of such former reservoirs are Empire-Abo reef trend of Texas-New Mexico; Cretaceous Stuart City shelf margin of Texas; Golden Lane-Pozo Rica trends of Mexico; Miocene pinnacles of the Salawati basin, Irian Jaya; and Kirkuk field on the Arabian Platform. Penultimate reservoirs are the linear sands of the San Joaquin and Ventura basins; Oligocene sands of south Louisiana; Triassic sands of the North Sea basin; Cretaceous Seaway sands in the Powder River basin; and the ancient Mississippi delta and cone. Latter reservoirs are found in the eastern shelf, Midland basin, and Bombay offshore basin, India. It is understood that for some of these reservoirs to become traps, the founding structural regime is modified, e.g., faulting, diapirism. Seals are classed as carbonate muds, evaporites, and faults. Source matter may be incorporated in marine shale and limestone deposited in anoxic environments. End_of_Article - Last_Page 946------------

SHELF AND SHELLOW BASIN OIL AS RELATED TO HOT‐DEEP ORIGIN OF PETROLEUM

Oil and gas pools in shallow basins of on the shallow, stable shevles of deeper sedimentary basins appear to be exceptions to the model of a hot‐deep origin of petroleum. However, the oil in shallow basins is directly associated with faulting extending out of the deepest parts of the basin. Evidence exists that some of these shallow basins have been much hotter in the past either from igneous activity of from a higher geothermal gradient. Uplift and erosion may also have removed substantial thicknesses of sediments in some of these basins. Oil on the stable, shallow, shelvees of deep basins could originated in the deeper part of the basin and undergone long lateral migration to the traps where it is now found. Conduits for such migration could have been sandstones in delta‐distributary systems (E Oklahoma and Kansas), reef trends (Alberta, Canada), or regional porosity and permeability in sheet carbonates (Anadarko basin. W. Oklahoma and Kansas). The model discussed herein allows us to (1) predict which areas of the stable shelves of deep basins should produce hydrocarbons and which areas should not, (2) predict the type of hydrocarbon (gas or oil), (3) set the limit of lateral updip migration, of hydrocarbons within any one formation in a basin, and (4) predict the downdip occurrence of hydrocarbons in the formation. The model should aslo help us determine which shallow cratonic basins should produce oil and which should not.

Exploring for Niagaran Pinnacle Reefs in Southern Michigan Basin: ABSTRACT

The search for hydrocarbon-bearing Silurian Niagaran pinnacle reefs commenced when exploration technology became sufficiently advanced to accurately locate areally small reefs. Starting in 1947, gravity methods were used to locate 90 reefs in southwest Ontario and southeast Michigan but, as the reef trend was pursued westward, gravity data became unreliable owing to the presence of highly variable, surface glacial till. Initial efforts with single fold seismic were also unsuccessful for the same reason. It required the development of CDP seismic techniques with adequate surface static correction before exploration could successfully be expanded into the rest of the reef trend. First, it was necessary to define reef seismic characteristics as it was not possible to see the reef directly. A synthetic seismogram study of known reefs in southeast Michigan indicated the initial indirect criteria: (a) thinning of seismic intervals above the reef and (b) pull-up below the reef interval. A CDP seismic survey confirmed these criteria and allowed optimization of field parameters. The first prospect drilled satisfied the seismic criteria and, in addition, exhibited a salt-solution feature common above reefs in southeast Michigan. However, high-velocity infill material was drilled instead of a reef. A second prospect was selected with the additional criterion of an isochron thick around the reef interval. This feature proved to be a residual salt pillow inside the isochron interval. To reduce the risk of encountering salt features a third prospect was selected south of the salt limit (as defined by geologic mapping). The prospect was modeled with best fit of seismic data for the reef case. This resulted in the Mobil No. 1A Brown Niagaran discovery. Several similar seismic features were drilled confirming the reef seismic characteristics. End_of_Article - Last_Page 736------------

Developments in Michigan in 1979

Niagaran reef exploration dominated drilling activity for the 11th straight year. Exploration and development drilling for these Middle Silurian reef reservoirs were heaviest in northern counties along the reef trend. Other pockets of high activity were associated with deeper development drilling in older fields in the central basin, in parts of southeastern Michigan, and in the Ingham-Calhoun-Eaton County region of southern Michigan. Exploration resulted in 70 new discoveries, one of which resulted from reworking of an earlier dry hole drilled in 1960. Of the new discoveries credited to 1979, 55 were new Niagaran reef reservoirs, 39 of which were located along various parts of the northern reef trend. Two new reef reservoirs in the Livingston-Oakland County region indicate additional prospects in this area of the basin. Exploration and development footage figures, derived from Department of Natural Resources, Geological Survey Division records, amounted to 1,146,515 ft exploratory and 1,150,710 ft development compared with 1,128,691 ft exploratory and 1,176,270 ft development drilled in 1978. An additional 202,791 ft, mainly gas-storage facility wells, is credited to 1979. Oil and gas production continued to set new records. Preliminary figures show that 35,428,411 bbl of oil (including condensate) and 161,707,877 Mcf of gas were produced in 1979. Both figures are new records for annual production. Niagaran reef reservoirs distributed along the northern reef trend accounted for about 72% of the oil and 84% of the gas produced in 1979.

Exploration History of South Texas Lower Cretaceous Carbonate Platform

The search for hydrocarbons in reservoirs of the Lower Cretaceous of south-central Texas has been continuous for more than 60 years. Accumulations have been found in significant quantities in only four areas: (1) the very shallow fault traps high on the San Marcos arch in Caldwell and Guadalupe Counties, (2) a fault trend stretching across central Atascosa County, (3) a fault trend extending from southeastern Atascosa County to southern Gonzales County, and (4) a narrow, elongate band extending across the entire area known as the Stuart City reef trend. Additional minor discoveries are widely scattered in the Maverick basin and San Marcos arch. Reservoirs which contain the hydrocarbons were deposited in many environments, all related to a broad carbonate shelf covered by an extremely shallow sea. The sea deepened dramatically at the shelf margin parallel with a reef trend. Dolomites contain the best accumulations in the fault trends, and porosity and permeability are reasonably good. Generally, limestones in the reef trend were not extremely porous initially, and late cementation has diminished even that porosity making the reservoir of lesser quality. Oil is the dominant hydrocarbon in the shallow fields, is less dominant in the other fault trends, and is nonexistent in the reef reservoirs. Proved ultimate hydrocarbons for the platform are about 363 million bbl of oil and 1.7 Tcf of gas. Reserves for the reef trend's dry gas reservoirs are difficult to estimate because of highly variable reservoir conditions, but they should fall between 1 and 1.5 Tcf. Exploration has been most intense for the uppermost Lower Cretaceous rocks. The Sligo limestone still holds the promise of success, but lies at considerable depths over much of the area. Edwards and Glen Rose rocks are more densely explored, but there are ample opportunities for new plays even in these formations. Geologists who examine cores and cuttings, determine depositional patterns, understand modern carbonate sedimentology, and study patterns of diagenesis will have an advantage in developing new concepts for exploration.