Calum I. Macaulay

Sandstone diagenesis and reservoir quality prediction: Models, myths, and reality

Models and concepts of sandstone diagenesis developed over the past two decades are currently employed with variable success to predict reservoir quality in hydrocarbon exploration. Not all of these are equally supported by quantitative data, observations, and rigorous hypothesis testing. Simple plots of sandstone porosity versus extrinsic parameters such as current subsurface depth or temperature are commonly extrapolated but rarely yield accurate predictions for lithified sandstones. Calibrated numerical models that simulate compaction and quartz cementation, when linked to basin models, have proven successful in predicting sandstone porosity and permeability where sufficient analog information regarding sandstone texture, composition, and quartz surface area is available. Analysis of global, regional, and local data sets indicates the following regarding contemporary diagenetic models used to predict reservoir quality. (1) The effectiveness of grain coatings on quartz grains (e.g., chlorite, microquartz) as an inhibitor of quartz cementation is supported by abundant empirical data and recent experimental results. (2) Vertical effective stress, although a fundamental factor in compaction, cannot be used alone as an accurate predictor of porosity for lithified sandstones. (3) Secondary porosity related to dissolution of framework grains and/or cements is most commonly volumetrically minor (2%). Exceptions are rare and not easily predicted with current models. (4) The hypothesis and widely held belief that hydrocarbon pore fluids suppress porosity loss due to quartz cementation is not supported by detailed data and does not represent a viable predictive model. (5) Heat-flow perturbations associated with allochthonous salt bodies can result in suppressed thermal exposure, thereby slowing the rate of quartz cementation in some subsalt sands.

Methods of laser-based stable isotope measurement applied to diagenetic cements and hydrocarbon reservoir quality

Abstract The stable isotopic compositions of diagenetic minerals can provide valuable constraints on the sources, precipitation temperatures and relative timing of cements in reservoir rocks. This type of information is essential when trying to understand and predict the distribution of cements in the subsurface, and their impact on reservoir quality. Conventional isotope methods contribute to answers to many diagenetic problems, but where core or time are scarce, or where good mineral separation is unobtainable, laser-based stable isotope methods offer several advantages. These include the ability to analyse carbonates, sulphides and anhydrite in situ with 50-100 m resolution, simple and clear sample and analysis viewing optics, savings on sample preparation time and greatly reduced sample size requirements. Diagenetic silicates such as quartz and clay cements cannot be analysed in situ by laser but, where in situ analysis of quartz δ18O is demanded, ion microprobe analysis can provide very high resolution (20-30 μm) capability with a precision of ±1‰.

Implications of linearly correlated oxygen and hydrogen isotopic compositions for kaolinite and illite in the Magnus Sandstone, North Sea

AbstractAuthigenic kaolinite and illite are important diagenetic minerals in the Magnus Sandstone, a giant oil reservoir in the northern North Sea. These clay minerals, separated from three wells, show considerable ranges in their oxygen isotopic composition (δ8OSMOW = +9 to + 16%) and hydrogen isotopic composition (δDSMOW = - 55 to - 105%). The variations in δ18O and δD are positively linearly correlated with a high degree of statistical significance for both kaolinite and illite:n

Distribution, chemistry, isotopic composition and origin of diagenetic carbonates; Magnus Sandstone, North Sea

begin{array}{c}{rm{Kaolinite}}:;;{rm{n}}=12;;;;{rm{delta}D}=6.1;;{rm{{delta}}^{18}}{rm{O}}-169;;;;{rm{r}}=0.66(>95%) {rm{Illite}}:;;;;;{rm{n}}=11;;;;;;;{rm{delta}D}=5.9;;;{rm{{delta}}^{18}}{rm{O}}-159;;;;{rm{r}}=0.78(>99%).end{array}

Oil migration makes the difference: regional distribution of carbonate cement δ13C in northern North Sea Tertiary sandstones

Kaolinite:n=12;δD=6.1δ18O−169;r=0.66(>95%)Illite:n=11;δD=5.9δ18O−159;r=0.78(>99%).n Formation of the clays in a pore fluid of uniform isotopic composition over a range of temperatures appears unlikely. It is suggested that the observed relationships between clay mineral δ18O and δD are perhaps best explained by a model of precipitation at more or less constant temperature from pore fluids which varied isotopically across the oilfield. The isotopic composition of the formation waters would then lie along the line: δDw = 6.2 δl8Ow - 50. This is most plausibly interpreted as a mixing line with suggested minimal endmembers at (δ18O, δD) values of (+4, -24) and (-4, -76). The first of these represents reasonable isotopic values for Magnus Sandstone formation waters. Although δ18O of the second is compatible with an evolved Cretaceous meteoric water, its δD value is difficult to understand in the context of the model.

Pore water evolution in oilfield sandstones: constraints from oxygen isotope microanalyses of quartz cement

When quartz-rich sands are buried and heated, pore space is gradually filled by precipitation of quartz cement from aqueous formation fluids. Here we examine whether the presence of oil in the pore space can retard or halt this loss of porosity by slowing or stopping quartz cementation. The effect of oil fill on quartz cementation is examined by using the distribution of quartz cement in the Brae Formation deep-water sandstone reservoir of the Miller oil field (North Sea). Petrographic data demonstrate that sandstones from the oil zone have much less quartz cement, and more porosity, than sandstones from the water zone. Sandstones in both oil and water zones are compositionally and texturally identical and have been affected by a similar burial history. Kinetic modeling of the cementation process suggests that progressive oil charging has slowed quartz-cement growth rates by at least two orders of magnitude, halting it completely in the most extreme cases. Our data demonstrate that early oil charging in the crestal part of an anticline can preserve porosity in deeply buried sandstones. This knowledge is especially relevant to porosity prediction for petroleum exploration in deeply buried sandstones.

Regional distribution of diagenetic carbonate cement in Palaeocene deepwater sandstones: North Sea

ABSTRACT Diagenetic ferroan carbonates grew in the Upper Jurassic reservoir sandstones of the Magnus oilfield in porewaters which differed in composition across the field. These porewaters remained compositionally different and stratified for at least 35 M.y. Variations in carbonate chemistry across the field are attributable to these porewater variations, which resulted from displacement of marine depositional water from the crest of the field by meteoric water during late Cimmerian subaerial exposure. Original depositional facies and detrital mineralogy strongly influenced diagenetic carbonate distribution. Rare diagenetic calcite occurs as discrete rhombic crystals. Diagenetically late magnesian siderites have developed throughout the reservoir sandstone and are commonly intimately associated with altered detrital biotite grains. Poikilotopic ankerite cement postdates calcite and siderite and occurs only adjacent to mudstones and in thin sandstones within mudstones. Three compositional growth zones in siderite crystals are observed across the field from crest to flank. In all three wells studied, a similar trend of compositional evolution through time is observed in both two and three zoned rhombs. First-formed siderite is relatively magnesian, intermediate zones are more ferroan, and outer zones are at least as magnesian as the first stage. These individual grain variations overprint a fieldwide variation where siderite is more ferroan in the crestal samples (up to 87 mol % Fe + Mn) and more magnesian downdip (up to 58 mol % Mg). This reflects the greater influence of relatively Fe-rich meteoric-derived water in the crest and the greater influence of marine-derived Mg-rich porewater downdip. Ankerite shows a similar variation in Fe and Mg abunda ces across the field (crest and flank maximum 25 and 17 mol % Fe + Mn respectively, 27 and 43 tool % Mg) and developed due to release of Mg, Fe, Ca and HCO3- ions from mudstones into adjacent sandstones following dissolution of detrital minerals and organic decarboxylation reactions. Both siderite and ankerite have lower 18O at the crest of the oilfield than downdip (respectively siderite 16.0 and 17.6 SMOW; ankerite 17.7 and 21.4). These differences in 18O reflect the retention during burial diagenesis of a larger component of meteoric water in the crest of the field below the unconformity, whereas downdip porefluid contained a larger marine-derived component. Strong organic influence on 13C (-8.0 to -14.6 PDB for magnesian siderite; -7.7 to -13.6 for ankerite), closed system 34S values (up to 15.7 for late cubic pyrite), and stratified 18O from crest to flank of the field argue against large scale porewater movements. Diagenetic porewater stratification is strongly supported by the parallel, but distinct, geochemical fingerprints of siderite and ankerite cements from the crest to the flank of the field.

Diagenetic porosity creation in an overpressured graben

Abstract In the Miller Field, diagenetic quartz abundance, isotopic compositions and salinities of quartz-cementing fluids display a distinct pattern which is related to the structural depth of the reservoir sandstones. Quartz cement volumes increase from the crest of the field (average 6.0±1.5%) towards the flanks of the field (average 13.2±2.1%) and directly reduce reservoir porosity. By integrating petrographic observations with results of fluid inclusion measurements and O isotope analyses of diagenetic quartz, the pattern of quartz cementation is seen to be related to the reservoir filling history. Oil filled the crest of the reservoir first and prevented extensive quartz cementation. At greater depth in the reservoir oil zone, quartz overgrowths continued to precipitate until inhibited by the developing oil column. Oxygen isotope compositions of diagenetic quartz imply that quartz cement continued to precipitate in the water zone of the reservoir up to the present day.