Dissolution Of Carbonate Cement Research Articles

Diagenetic and porosity evolution of conglomerate sandstones in Bayingebi Formation of the Lower Cretaceous, Chagan Sag, China–Mongolia frontier area

The fan delta conglomerate sandstones of Bayingebi Formation including conglomerates and pebbly sandstones in the Chagan Sag are reservoir for large accumulations of hydrocarbons. Based on observation of cores, thin sections, SEM and CL, combined with application of fluid inclusion and carbon and oxygen isotopes, it indicates that the conglomerate sandstones are mainly feldspathic litharenites with immature texture. It has considerable heterogeneity with a wide range of porosity from 0.3% to 15.3% and the permeability from 0.004 mD to 1168 mD. This study discusses conglomerate sandstones diagenesis and its controls on reservoir quality. Its eodiagenesis is primary compaction and the minor of calcite cementation. The subsequent mesodiagenesis includes weak compaction, precipitation of quartz overgrowth and feldspar overgrowth, albitization, dissolution of early carbonate cement and metastable framework grains, late carbonate cementation, and illitization.A comparison between porosity-depth data and normal compaction curve of conglomerate sandstones shows two groups. Group “A” is mainly composed of tight conglomerate sandstones with permeability less than 1 mD and porosity less than 10%. Petrology studies show that two types of the tight conglomerate sandstones developed in this group. One type, mainly depositing in the thinly bedded subaqueous channels of fan delta front, is characterized by abundant clay minerals occluding intergranular pores. The other type, mainly depositing in the thinly bedded subaqueous channels or along sandstone/mudstone interface of thickly bedded subaqueous channels, is characterized by abundant carbonate cements occluding intergranular and intragranular pores. Group “B” is mainly composed of conglomerate sandstones with higher permeability more than 1 mD and porosity ranging from 5% to 16% corresponding to the burial depth from 2200 to 3400 m. It mainly deposited within the thickly bedded subaqueous channels of fan delta front. Significant dissolution of carbonate cement, feldspars, and other metastable framework grains by organic acids and CO2 generated from organic maturation are the major cause of abnormally high porosity.

Factors controlling reservoir properties and hydrocarbon accumulation of lacustrine deep-water turbidites in the Huimin Depression, Bohai Bay Basin, East China

Lacustrine deep-water turbidite plays are a novel area for exploration in the Huimin Depression, Bohai Bay Basin. Turbidites in the Shang 847 block, a typical turbidite play in the Huimin Depression, provide an opportunity to study the factors controlling the reservoir properties and hydrocarbon accumulation in lacustrine turbidite sandstones. The reservoir quality of turbidite sandstones (very fine-grained, moderately to well sorted, mainly lithic arkose) in this study area are mainly controlled by the distribution patterns of carbonate cements and pseudomatrix. Significant inverse relationships exist between the volume of carbonate cement and both porosity and permeability of the turbidite sandstones. Carbonate cement is located preferentially near the margins of the sandstone bodies. Sandstones with distance from the sandstone–mudstone contact surface less than 0.7 m or with thickness less than 1.2 m are commonly tightly cemented (carbonate cement >15%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The source of carbonate cement was most likely external, probably derived from the surrounding mudstone. Most pore-filling carbonate cements occurred during late diagenesis at burial depths greater than 2200 m. The petrophysical properties of turbidites have a positive relationship with the content of kaolinite and chlorite, but have a negative relationship with the content of illite. 2-D and 3-D reconstructions of non-oil bearing and oil-bearing layers indicate that dissolution of carbonate cement, feldspars and unstable rock fragments was more developed in oil-bearing layers than in non-oil bearing layers and hance oil-bearing layers have higher porosity and larger pore sizes. Petrophysical property appears to have a significant effect on the hydrocarbon accumulation in the turbidite sandstones. Sandstones with porosities lower than 9% and/or permeabilities lower than 0.78 mD are not prone to contain oil.

The effect of CO2 on the mechanical properties of the Captain Sandstone: Geological storage of CO2 at the Goldeneye field (UK)

Geological storage of CO2 in clastic reservoirs is expected to have a variety of coupled chemical–mechanical effects, which may damage the overlying caprock and/or the near-wellbore area. We performed conventional triaxial creep experiments, combined with fluid flow-through experiments (brine and CO2-rich brine) on samples of poorly consolidated, carbonate- and quartz-cemented Captain Sandstone from the Goldeneye field. The main goal was to study the effect of carbonate cement dissolution on mechanical and ultrasonic properties, as well as on the failure strength of the material. Our experiments were performed under in situ reservoir conditions, mimicking reservoir depletion and injection. Although total dissolution of calcite was observed, and confirmed by microstructural and fluid chemistry analyses, it did not affect the rock mechanical properties, nor was any measurable rock strength reduction observed. This is most likely because grain-to-grain contacts were sufficiently quartz-cemented and quartz is not affected by CO2-rich brine. Failure data for the Captain Sandstone showed that the stress conditions under which CO2 injection will take place remain far away from the failure envelope. Therefore, CO2 injection is not expected to lead to shear failure of the reservoir. However, longer-term chemical reactions, involving minerals such as feldspar, clays or micas, still require more research.

An experimental study of CO2–brine–rock interaction at in situ pressure–temperature reservoir conditions

A detailed investigation of CO2–brine–rock interactions, through a core flooding laboratory experiment, was carried out under simulated reservoir conditions (100°C and 24MPa). Changes in the ionic chemistry of the outlet solution, combined with core scanning electron microscopy (SEM) and bulk-rock X-ray diffraction (XRD) analysis of the core pre- and post-experiment reveal new insights into CO2–brine–rock interactions. Minerals such as potassium (K) feldspar, albite, calcite, and ankerite are variably dissolved after the experiments. Calcite is the mineral most affected by dissolution, followed by ankerite, whereas dissolution of feldspar minerals is minimal. Small amounts of kaolinite and solid phases were generated as a result of the experiment. The solid phases are mainly comprised of C, O, Na, Cl, Al, and Si, and are presumed to be the transitional products in the formation of carbonate minerals. The very low fluid penetration rate in the experiment resulted in significantly reduced contact area between the acidic CO2 fluid and minerals in the cores, resulting in low rates of feldspar dissolution. Core permeability decreased substantially throughout the experiment, although core porosity remained unchanged. The permeability reduction is the result of precipitation of new mineral phases (e.g., kaolinite and solid phases), and potentially also the presence of clay particles released by the dissolution of carbonate cement, which have then been transported in the fluid flow path and accumulated at pore throats. The results provide new insights into CO2 trapping mechanisms in depleted oil and gas reservoirs, and into the potential formation damage that may result from massive injections of CO2 into reservoirs during enhanced oil recovery programs.

Impact of Late-Accumulated Mantle-Derived CO2 on Quality of Paleogene Clastic Reservoir at Actic Area, Qin Nan Sag

In this paper, the origin and accumulation time of CO2, and the transformation of clastic reservoir bed by CO2 in the A2 structure at the actic area of Qin Nan Sag were studied. The elevated δ13CCO2, R/Ra values and 40Ar/36Ar values showed that CO2 was mantle derived. CO2-bearing inclusions were associated with hydrocarbon inclusions, and CO2-bearing inclusions included hydrocarbon components, showing migration and filling of CO2 and hydrocarbon at the same stage. Basin modeling and homogenization temperature of inclusions indicated that the time of hydrocarbon and CO2 accumulation was mainly less than 3 Ma. CO2 late filling resulted in strong dissolution of feldspar and carbonate cement, with a high content of intragranular dissolution pores and a high proportion of intergranular primary pores, mostly from carbonate cement dissolution. Acidic environment inhibited illite growth, and dissolution of feldspar and acidic environment promoted formation of kaolinite. CO2 late filling brought out obvious thermal fluctuation, which was in favor of redistribution of dissolved matter, and top strong cementation was found at rock cores. Because of late accumulation of CO2, acidic environment of reservoir bed lasting for a long time, reservoir bed at a high temperature, undergrown dawsonite showed weak influence on reservoir bed quality. Dissolution of feldspar and carbonate cement, inhibition of illite growth, a high content of authigenic kaolinite, a low content of dawsonite, and redistribution of dissolved matter played a decisive role in improving reservoir quality, with rarely seen high permeability.

On the formation of dissolution pipes in Quaternary coastal calcareous arenites in Mediterranean settings

AbstractA large number of uniform cone‐shaped dissolution pipes has been observed and studied in Quaternary coastal calcareous arenites in Apulia and Sardinia (Italy) and Tunisia. These cylindrical tubes have a mean diameter of 52·8 cm and are up to 970 cm deep (mean depth for sediment‐free pipes is 1·38 m). They generally have smooth walls along their length, are perfectly vertical and taper out towards their bottoms. Their development is not influenced by bedding nor fractures. Sometimes their walls are coated by a calcrete crust. Their morphology has been studied in detail and their relationships with the surrounding rocks and with the environment have been analysed. The perfectly vertical development is a clear evidence of their genesis controlled by gravity. The depth of the dissolution pipes can be described by an exponential distribution law (the Milanovic distribution), strongly suggesting they developed by a diffusion mechanism from the surface vertically downward. We believe dissolution pipes preferentially form in a covered karst setting. Local patches of soil and vegetation cause infiltration water to be enriched in carbon dioxide enhancing dissolution of carbonate cement and local small‐scale subsidence. This process causes the formation of a depression cone that guides infiltrating waters towards these spots giving rise to the downward growth of gravity‐controlled dissolution pipes. A change of climate from wetter phases to drier and hotter ones causes the formation of a calcrete lining, fossilizing the pipes. When the pipes become exposed to surface agents by erosion of the sediment cover or are laterally breached the loose quartz sand filling them may be transported elsewhere. Copyright © 2010 John Wiley & Sons, Ltd.

Stable isotopes (2H, 18O and 13C) in groundwaters from the northwestern portion of the Guarani Aquifer System (Brazil)

The groundwater flow pattern of the western part of the Guarani Aquifer System (GAS), Brazil, is characterized by three regional recharge areas in the north, and a potentiometric divide in the south, which trends north–south approximately. Groundwater flow is radial from these regional recharge areas toward the center of Parana Sedimentary Basin and toward the western outcrop areas at the border of the Pantanal Matogrossense, because of the potentiometric divide. The isotopic composition of GAS groundwater leads to understanding the paleoclimatic conditions in the regional recharge areas. The δ18O and δ2H isotopic ratios of GAS groundwaters vary, respectively, from –9.1 to –4.8‰ V-SMOW and –58.4 to –21.7‰ V-SMOW. In the recharge zones, enriched δ18O values are observed, while in the confined zone lighter δ18O values are observed. These suggest that climatic conditions were 10°C cooler than the present during the recharge of these waters. The δ13C ratios in groundwater of GAS, in the study area, vary from –19.5 to –6.5‰ VPDB, increasing along the regional flow lines toward the confined zone. This variation is related to dissolution of carbonate cement in the sandstones.

Diagenetic evolution of the Ansian–Pliensbachian Adigrat Sandstone, Blue Nile Basin, Ethiopia

The Blue Nile Basin is located in the Central Plateau of Ethiopia. The basin consists of Precambrian basement, Palaeozoic and Mesozoic sedimentary rocks and Tertiary volcanic rocks. The sedimentary successions and Adigrat Sandstone reach a maximum thickness of 3000 and 800 m, respectively. The formation is composed of mudstone, finely laminated siltstone, very fine-grained cross-bedded sandstone, coarse to medium-grained sandstone, massive to crudely cross-bedded gravely sandstone and massive to crudely-bedded conglomerate. In the Blue Nile Basin, the Adigrat Sandstone was deposited in alluvial fan, fluviatile and lacustrine depositional environments. The formation has a complex diagenetic history and cemented by silica, carbonate, kaolinite and hematite with minor amounts of dolomite, illite, chlorite and feldspar overgrowths. Depositional environment, burial history and diagenetic processes are the major factors, which control the porosity and permeability of the Adigrat Sandstone. Primary porosity is preserved due to framework grain stability. Dissolution of carbonate cements created a certain amounts of secondary porosity in medium to coarse-grained sandstones, siltstones and mudstones facies. The porosity and permeability reach up to 20.4% and 710 mD, respectively. The medium-coarse-grained sandstones are porous and potential for oil and gas reservoir, whilst low-permeability siltstones and mudstones are possible gas reservoir.

ORGANIC ‐ INORGANIC INTERACTIONS IN OILFIELD SANDSTONES: EXAMPLES FROM TURBIDITE RESERVOIRS IN THE CAMPOS BASIN, OFFSHORE EASTERN BRAZIL

Turbidite sandstone reservoir rocks in the Campos Basin, offshore eastern Brazil, show evidence of a number of interactions among organic and mineral phases during diagenesis. These include extensive dissolution of plagioclase, precipitation of kaolinite into intergranular and intragranular pores, dissolution of carbonate cements and grains, as well as selective deposition of organic films on kaolinite aggregates, dissolved plagioclase and carbonate grains. These processes are connected with the biodegradation of hydrocarbons within the reservoir, related to the influx of meteoric fluids possibly during sea‐level lowstands, through major stratigraphic sequence boundaries and large‐scale faults. Oil biodegradation generated organic solvents responsible for mineral alteration, as well as heavy oils rich in asphaltenes. The action of organic solvents in the reservoirs is indicated by the extensive dissolution of feldspars, quartz, garnets and kaolinite, and the negative mass balance between dissolved feldspar and precipitated kaolinite, indicating aluminum mobilization. Asphaltene films and coatings may affect the wettability of the reservoir rocks and the evaluation of hydrocarbon saturation in the reservoirs by resistivity logs.These various inorganic and organic processes are apparently interrelated in the diagenesis of the Campos Basin turbidite reservoir sandstones. These interactions should be considered in future models of the basin and its petroleum system, as well as for the creation of geochemical models capable of predicting the quality of the reservoirs and the occurrence of degraded heavy oils.

Recharge velocity and geochemical evolution for the Permo-Triassic Sherwood Sandstone, Northern Ireland

The Triassic Sherwood Sandstone Group is a major European aquifer system. It is also the principal groundwater source in Northern Ireland. However, key aspects of its regional hydrogeology, such as age distribution and geochemical evolution, remain largely unknown. Here the groundwater geochemistry and isotopic composition were investigated in order to evaluate groundwater recharge and flow processes in a complex regional hydrogeological setting. The dominant geochemical processes, such as dissolution of carbonate cements were determined from the major and trace element chemistry. Stable and radio-isotope measurements were taken as residence time and flow path indicators and, together with physical and geochemical groundwater modelling, revealed groundwater ages of up to 9000 years. The importance of infiltration from overland flow from springs deriving water from the adjacent Cretaceous chalk aquifer and subsequently re-infiltrating into the Sherwood Sandstone was confirmed. In addition, evidence was found of a slow recharge component through low conductivity mudstones that yielded significant groundwater resident times throughout the Lagan Valley. These findings provide improved understanding of groundwater flow processes in Northern Ireland and serve as an example of methods that can be applied to water management elsewhere.

Mineralogical and geochemical consequences of the long-term presence of CO 2 in natural reservoirs: An example from the Springerville–St. Johns Field, Arizona, and New Mexico, U.S.A.

The Springerville–St. Johns CO 2 field in eastern Arizona and western New Mexico is one of more than a dozen gas fields developed within the Colorado Plateau and Southern Rocky Mountain region. Extensive travertine (CaCO 3) deposits record a long history of CO 2 migration and leakage to the atmosphere. The oldest travertine deposits may have formed during the initial filling of the CO 2 reservoir when groundwaters exsolved CO 2 upon reaching the surface. The youngest travertine deposits are associated with springs on the floor of the Little Colorado River valley, but travertine deposition appears to be insignificant today. Older deposits occur up to 325 m above the valley floor. Geologic relationships suggest travertine deposition began in the late Pleistocene after volcanic activity ended at ∼0.3 Ma. Most of the CaCO 3 could have been derived from dissolution of the underlying limestones and dolomites. Interactions between the reservoir fluids and rocks were observed in core samples from one of the intervals that produced dry gas. These reactions resulted in the dissolution of carbonate cements and detrital feldspars and the formation of dawsonite and kaolinite. Geochemical simulations suggest that the dawsonite could have been deposited when the CO 2 fugacity reached 20 bars and that the kaolinite formed as the CO 2 fugacity decreased. Corrosion of drill pipe by acidic waters and a pronounced HCO 3 anomaly above the CO 2 reservoir provide evidence of a continuing flux of CO 2 from depth. CO 2 storage occurs primarily as dissolved carbonate species and as gas accumulations. Only a small percentage of the CO 2 was sequestered in secondary minerals.

Strontium isotopic identification of water-rock interaction and ground water mixing.

87Sr/86Sr ratios of ground waters in the Bighorn and Laramie basins' carbonate and carbonate-cemented aquifer systems, Wyoming, United States, reflect the distinctive strontium isotope signatures of the minerals in their respective aquifers. Well water samples from the Madison Aquifer (Bighorn Basin) have strontium isotopic ratios that match their carbonate host rocks. Casper Aquifer ground waters (Laramie Basin) have strontium isotopic ratios that differ from the bulk host rock; however, stepwise leaching of Casper Sandstone indicates that most of the strontium in Casper Aquifer ground waters is acquired from preferential dissolution of carbonate cement. Strontium isotope data from both Bighorn and Laramie basins, along with dye tracing experiments in the Bighorn Basin and tritium data from the Laramie Basin, suggest that waters in carbonate or carbonate-cemented aquifers acquire their strontium isotope composition very quickly--on the order of decades. Strontium isotopes were also used successfully to verify previously identified mixed Redbeds-Casper ground waters in the Laramie Basin. The strontium isotopic compositions of ground waters near Precambrian outcrops also suggest previously unrecognized mixing between Casper and Precambrian aquifers. These results demonstrate the utility of strontium isotopic ratio data in identifying ground water sources and aquifer interactions.

Geochemistry and Paragenesis of Heulandite Cements in a Miocene Marine Fan-Delta System of the Pohang Basin, Republic of Korea

AbstractIn the Pohang area of Korea, heulandite occurs as cements in conglomerate and sandstone of a Miocene marine fan-delta system resting on Eocene dacitic volcanics. Three types of heulandite cements are distinguishable in the fan-delta sediments on the basis of texture, chemical composition and authigenic mineral association. The earliest type I heulandite (Si/(A1+Fe): 3.5–3.8) occurs as microcrystalline (10–30 μm) in situ crystallites that replace volcanic matrix and are intermixed with early-formed smectite. Type II heulandite (Si/(A1+Fe): 3.2–3.6) occurs as medium-grained (30–60 μm) crystal aggregates rimming intergranular cavities. Type III heulandite (Si/(A1+Fe): 3.6–4.1) is the last to form and is a composite phase of heulandite-clinoptiloite, which occurs as unusually coarse (50–200 μm) single-crystal cement associating with late-formed smectite and hematite.These characteristic heulandite cements were formed by alteration of volcaniclastic sediment during shallow burial (burial temperature: 40–60 °C) and uplift in marine pore fluid diluted by meteoric water. Sr isotope data for heulandite II (87Sr/86Sr: 0.706565–0.706598) and heulandite III (87Sr/86Sr: 0.707347–0.707432) indicate that the pore fluid was progressively mixed with meteoric water during burial and uplift but the Ca in the pore-filling heulandites has been derived mainly from dissolution of carbonate cements. Heulandite III, heulandite-clinoptilolite, was formed with an unusual coarsening and chemical zoning at somewhat diluted and disequilibrium conditions caused by the migration of oxygen-rich meteoric water during or after uplifting.

Abstract: Depositional Environments and Sandstone Diagenesis in the Tyler Formation (Pennsylvanian), Western North Dakota 

Thirty-three oil well cores were examined and approximately 3,100 oil well logs were used to determine the depositional environments of the Tyler Formation (Pennsylvanian) in northwestern North Dakota. Ninety sandstone thin-sections were described and twenty-nine sandstone samples were analyzed by scanning electron microscope/X-ray microanalysis techniques to characterize sandstone diagenesis. The Tyler Formation in northwestern North Dakota is correlative with the lower unit of the Tyler Formation in southwestern North Dakota. The upper unit of the Tyler Formation in southwestern North Dakota is not present in northwestern North Dakota, contrary to previous workers suggestions. The Tyler Formation in northwestern North Dakota consists of varicolored mudstone, medium-gray claystone, thin bituminous coal beds, dark-gray shale and limestone, and gray sandstone. The upper unit of the Tyler Formation in southwestern North Dakota consists of gray sandstone, dark-gray limestone and shale, and varicolored mudstone. Lenticular sandstones present in the middle and rarely at the base of the formation, which occur in northeast-southwest linear trends, indicate that the Tyler Formation in northwestern North Dakota was deposited as a river channel system on a low-lying, prograding coastal plain. Depositional environments associated with the coastal plain include river channels, flood plains, lakes, estuaries, caliche paleosols, and backswamps. Throughout deposition of the Tyler Formation, several major river channels flowed in a predominantly southwest direction across a low-lying coastal plain and transported quartz sand toward a delta or shoreline, not identified in this study, at the margin of a shallow epeiric sea. Initially, the presence of detrital clay and infiltration clay and early hematite and chlorite coatings on quartz grains was the most important factor influencing porosity reduction in Tyler sandstones. The first major diagenetic event responsible for porosity reduction was the development of authigenic quartz overgrowths. Other cements that have contributed to porosity reduction in Tyler sandstones include amorphous silica (opal), calcite, ankerite, siderite, anhydrite, barite, hematite, and pyrite, In addition, authigenic kaolinite, illite, and chlorite have reduced porosity in Tyler sandstones. Dissolution of carbonate cement resulted in the formation of secondary porosity. Sandstone diagenesis took place shortly after sand was deposited in a marine environment, while sediments were being flushed with meteoric ground water, and while sands were being flushed with chemically evolved pore water released after diagenesis and compaction of interbedded mud-rich sequences. River-channel sandstones in northwestern and southwestern North Dakota and barrier-island sandstones present only in southwestern North Dakota contain considerable amounts of intergranular porosity. Petroliferous sandstones in southwestern North Dakota are fine- to medium-grained, well-sorted, texturally mature…

Diagenesis of an ‘overmature’ gas reservoir: the Spiro sand of the Arkoma Basin, USA

The Spiro sand is a laterally extensive thin sandstone of earliest Atokan (Pennsylvanian) age that forms a major natural gas reservoir in the western Arkoma Basin, Oklahoma. Petrographic analysis revelas a variety of diagenetic alterations, the majority of which occurred during moderate to deep burial. Early diagenetic processes include calcite cementation and the formation of Fe-clay mineral peloids and coatings around quartz framework grains. These clays, which underwent transformation to well-crystallized chamosite [polytype lb(β = 90°C)]. These clays, are particularly abundant in medium-grained channel sandstones, whereas illitic clays are predominant in fine-grained interchannel sandstones. Subsequent to mechanical compaction, saddle ankerite precipitated in the reservoir at temperatures in excess of 70°C. Crude oil collected in favourable structural locations during and after ankeritization. Whereas hydrocarbons apparently halted inorganic diagenesis in oil-saturated zones, cementation continued in the underlying water-saturated zones. As reservoir temperatures increased further, hydrocarbons were cracked and a solid pyrobitumen residue remained in the reservoir. At temperatures exceeding ∼140–150°C, non-syntaxial quartz cement, ferroan calcite and traces of dickite(?) locally reduced the reservoir quality. Local secondary porosity was created by carbonate cement dissolution. This alteration post-dated hydrocarbon emplacement and is probably related to late-stage infiltration of freshwater along ‘leaky’ faults. The study shows that the Spiro sandstone locally retained excellent porosites despite deep burial and thermal conditions that correspond to the zone of incipient very low grade metamorphism.

Diagenesis, Compaction, and Fluid Chemistry Modeling of a Sandstone Near a Pressure Seal: Lower Tuscaloosa Formation, Gulf Coast

Petrographic, isotopic, and fluid-inclusion evidence from normally and overpressured sand-stones of the lower Tuscaloosa Formation (Upper Cretaceous) in the Gulf Coast documents quartz-overgrowth precipitation at 90°C or less, calcite cement precipitation at approximately 100° and 135°C, and prismatic quartz cement precipitation at about 125°C. Textural evidence suggests that carbonate cement dissolution occurred before the second phases of calcite and quartz precipitation, and was followed by precipitation of grain-rimming chlorite and pore-filling kaolinite. Geochemical calculations demonstrate that present-day lower Tuscaloosa Formation water from 5500 m depth could either dissolve or precipitate calcite cements in model simulations of upward water low. Calcite dissolution or precipitation depends on PCO2 variability with depth (i.e., whether there is one or two-phase flow) or on the rate of generation of CO2 with depth. Calculations suggest that 105-106 rock volumes of water are required to flow through the section to precipitate 1-10% calcite cement. Compaction analysis suggests that late-stage compaction occurred in normally pressured sandstones after dissolution of carbonate cements, but was hindered in overpressured sandstones despite the presence of high porosity. These results document the inhibition of compaction by overpressured fluids and constrain the timing of pressure seal formation. Modeling results demonstrate that the proposed paragenesis used to constrain timing of pressure seal formation is feasible, and that most of the cement diagenesis occurred before the pressure seal became effective as a permeability barrier.

Models of burial diagenesis for deep exploration plays in Jurassic fault traps of the Central and Northern North Sea

With increasing burial depth, intergranular porosity declines in a predictable manner according to theoretical and empirically established mathematical relationships. In basins with simple structural and thermal histories, average porosity can often be represented as an exponential function of depth. There are, however, common significant deviations from such a simple model of porosity evolution. Four mechanisms are recognized by which enhanced porosity may be generated or maintained during burial: development of overpressures due to restricted pore fluid escape; inhibition of mechanical compaction by selective cementation; inhibition of cementation as a result of hydrocarbon accumulation; or generation of secondary porosity due to either grain or cement dissolution together with simultaneous removal of reaction products. Secondary porosity may be generated either near the surface by the ingress of dilute meteoric-derived waters or at depth by the generation of ‘aggressive’ pore fluids. Deep burial diagnesis may encompass both closed and open system porosity generating reactions. In closed systems, increase in temperature concomitant with burial overcomes kinetic barriers enabling dissolution of metastable detrital minerals. By contrast, in more open systems, movement of fluids from either mudstones or evaporites to either overlying or adjacent sandstones introduces chemical disequilibrium that may cause mineral dissolution. Rapid, intermittent movement of fluids along active faults may additionally introduce temperature disequilibrium to further facilitate mineral dissolution in the proximity of faults. Over geological periods of time, however, faults are barriers to fluid flow and provide a mechanism for generating overpressure. In the Central and Northern North Sea basins, an upper diagenetic regime is separated from a lower diagenetic regime by a regional cover of Cretaceous mudstones and chalks. The Cretaceous sediments provide a regional seal which often coincides with the development of overpressure above deep graben centres reflecting restricted pore water escape. Fluid and solute movement between these two regimes is only possible where faults or gas chimneys penetrate the Cretaceous seal. In the upper regime, porosity loss in Tertiary sediments broadly conforms to the predicted decline of porosity with depth. In the lower regime, Jurassic sandstones on structural highs are characterized by extensive secondary porosity resulting from feldspar grain and carbonate cement dissolution, best preserved where oil accumulation rapidly follows porosity generation. Enhanced porosity can be expected either where sandstones interdigitate with mudstones or in graben centre plays adjacent to faults. This contrasts with graben margin plays where faults are the locus of pronounced cementation and complex diagenetic sequences are developed. In the absence of either oil accumulation or overpressure, secondary porosity either compacts or is occluded by a characteristic deep burial authigenic mineral assemblage. The present heat flow in the North Sea can be interpreted in terms of a residual thermobaric fluid flow from basin centres to basin margins which was probably initiated during the early Tertiary, coincident with the onset of rapid thermal relaxation subsidence.

Origin of reddening and secondary porosity in Carboniferous sandstones, Northern Ireland

Abstract Carboniferous sandstones in the Ballycastle district of Northern Ireland were deposited in fluvio-deltaic environments. Significant secondary porosity was generated in the sandstones, particularly in red-coloured sandstones, due to the dissolution of carbonate cement. Minor secondary porosity was also created by the leaching of feldspar grains. Virtually all the observed porosity in the Carboniferous sandstones has a secondary origin. Subsequently, the precipitation of kaolinite reduced the porosity. The red-coloured sandstones are important in showing the depth of invasion of oxidising meteoric fluids following late Carboniferous-Permian uplift. The red colour is due to iron oxides liberated during the dedolomitization of a ferroan dolomite cement. Several instances of reddened Carboniferous strata across the UK probably have a similar origin and are potential oil and gas reservoirs as reddened sandstones may have a high secondary porosity.

Effects of Thermal Sulfate Reduction on Permeability Distributions of the Norphlet Formation

Framework grain coatings are common in the Norphlet. Clay coatings are present throughout the depth range (16,000 to 22,000 ft) over which significant variations of permeability occur. Pyrobitumen coatings occur within the deep, low-permeability interval (approximately 18,000-20,000 ft) and the deeper (greater than 20,000 ft), more permeable interval. Both types of coatings may be important in preserving porosity during portions of the burial history of the Norphlet sandstones; however, their occurrence does not correlate with observed variations in permeability. Diagenetic reactions associated with thermal sulfate reduction provide a mechanism for the dissolution of carbonate cements in deep zones characterized by enhanced permeabilities. Protons generated from dissociation of H{sub 2}S produced during sulfate reduction results in the dissolution of carbonate cements. To be effective, this process must remove cements that precipitated after grain coatings. Uncoated quartz grains produce quartz overgrowths. Vertical permeability distributions within the Norphlet suggest that early and intermediate diagenetic carbonate and sulfate cements, sourced from the intercalated, interdunal pond strata, were redistributed throughout the dune sands. Portions of carbonate cements were either dissolved or the extent of their precipitation was reduced as thermal decarboxylation was closely followed by the initiation of sulfate reduction. Hence, variations in Norphlet permeabilitymore » distributions are in part the result of diagenetic reactions associated with thermal sulfate reduction and, therefore, can be predicted using kinetic modeling of sulfate reaction.« less

Carbon Dioxide Injection and Resultant Alteration of the Weber Sandstone, Rangely Field, Colorado (1)

Geologic interpretations made during the current enhanced oil recovery project at Rangely field (Rio Blanco County, Colorado) have shown the relationships between alteration of reservoir mineralogy and texture, changes in produced water composition, and increased problems with oil production. The bottom-hole pH of Weber brine has decreased from approximately 7.5 to 4.5 since the initiation of CO[2] injection into the Pennsylvania-Permian Weber Sandstone in the central portion of the field. Much of the Weber is partially cemented with carbonate minerals, including ferroan calcite and ferroan dolomite, with authigenic clay minerals, predominately illite and mixed-layer smectite/illite, also present. These minerals are affected by the lowered pH of the CO[2] flood. Changes in the chemistry of produced water are associated with alteration of reservoir mineralogy. The CO[2] flood has caused substantial increases in the concentrations of iron, calcium, and magnesium in the produced brine from the dissolution of carbonate cements and, perhaps, authigenic clays and detrital feldspars. Produced water from some wells has experienced large changes in barium and sulfate concentrations. An increase in bromide concentration indicates that previously segregated portions of the reservoir, which contained very saline original formation brine, have been accessed by the carbonated water. Hypotheses based on the water-chemistry changes were confirmed in core-flood experiments. These experiments also indicated that there was no net change in permeability following CO[2] injection.