North Sea Formation Waters Atlas
... Aluminium and silicon, although sparingly soluble in sedimentary formation waters, are ubiquitous in clastic sediments because they are present in fine fraction clay minerals and coarse fraction detrital micas and feldspars. Iron also has low solubility in formation waters, as indicated by the typically low, to below detection, concentrations in sedimentary formation waters (Warren and Smalley, 1994). In contrast, magnesium is relatively soluble in formation waters, typically present at the thousands of ppm concentration. ...
... In contrast, magnesium is relatively soluble in formation waters, typically present at the thousands of ppm concentration. Formation water chemistry data that report both dissolved iron and magnesium from UK oil and gas fields have been compiled (Warren and Smalley, 1994;Worden et al., 2006a). The absolute and relative concentrations of dissolved iron and magnesium are compared in Figure 12. ...
... Magnesium is a diagenetically interesting element as it is relatively soluble and is commonly found at concentrations of thousands of parts per million in sedimentary formation waters (Hanor and McIntosh, 2007;Warren and Smalley, 1994) (Fig. 12). Moreover, dolomitization is common in carbonates, and dolomite and ankerite cements are common mesogenetic (i.e. ...
Chlorite, an Fe- and Mg-rich aluminosilicate clay, may be either detrital or authigenic in sandstones. Detrital chlorite includes mineral grains, components of lithic grain, matrix and detrital grain coats. Authigenic chlorite may be grain-coating, pore-filling or grain-replacing. Chlorite can be observed and quantified by a range of laboratory techniques including light optical and scanning electron microscopy and X-ray diffraction; the presence of chlorite in sandstone can be identified by the careful integration of signals from downhole logs. Grain-coating chlorite is the only type of chlorite that can help sandstone reservoir quality since it inhibits quartz cementation in deeply buried sandstones. Grain coats are up to about 10 μm thick and typically isopachous on all grain surfaces; they result from rapid indiscriminate nucleation at high levels of chlorite supersaturation in the pore waters and then growth of appropriately oriented nuclei as ultra-thin, roughly equant crystals. Chlorite can have many possible origins, but it is likely that grain-coating chlorite results from closed system diagenesis at the bed scale. Chlorite sources include transformation of detrital Fe-rich berthierine, transformation of Mg-rich smectite, reaction of kaolinite with sources of Fe and breakdown of volcanic grains. The specific origin of chlorite controls its composition, with marine sandstones having a berthierine source and continental sandstones having a smectite source. Incorporation of precursor clays required for chlorite growth can be achieved by a variety of processes; these most commonly occur in marginal marine environments possibly explaining why Fe-rich chlorite coats are most commonly found in marginal marine sandstones.
... Land and Prezbindowski 1981;Land et al. 1988); basin plumbing (Bethke and Marshak 1990;Harrison and Summa 1991); reserves estimation (Worthington and Johnson 1987) and scale prediction. This contribution reviews our present understanding of formation-water compositions and variations in the North Sea using the present literature and describes the progress made so far in the compilation of a new atlas of North Sea formation-water data currently in preparation (Warren et al. 1993). ...
... However, salinities are generally lower than seawater throughout the Northern North Sea, although the Heather Field study highlighted heterogeneity (Glasmann et al. 1989). Aplin et al. (in press) compared the distribution of formation-water salinities Fig. 7. Barium concentration (mgl ! ) in North Sea formation waters (data from Warren et al. 1993). ...
... The ideal dataset of North Sea formation waters would combine the comprehensive data of the NOCS dataset (Egeberg and Aagaard 1989) with the basin-wide coverage of the water-resistivity catalogue (SPWLA 1989) and the lateral and vertical detail of the Heather and Piper studies (Glasmann et al. 1989;Burley et al. 1989). Such a volume is now being prepared (Warren et al. 1993) under the auspices of the Petroleum Group of the Geological Society. ...
Significant variations in the salinity, chemical and stable isotopic composition of formation waters can be observed in the existing published data from the North Sea Basin. Variations occur at all scales, from intra-formational and within-field to basin-wide variations in water chemistry within and between formations. Clearly, the present-day North Sea Basin waters are highly heterogeneous. These variations have important implications. Various aspects of formation-water chemistry impact upon reserves estimates (/?w) and scale prediction (e.g. Ba, Sr, S04), and also yield valuable information on the processes of water-rock interaction and diagenesis leading to modification of reservoir quality. However, present understanding of the processes causing the compositional heterogeneities is limited by the sparse coverage of the existing published data. Consequently, a new effort is being made to compile formation-water data for all fields in the greatest detail possible. Interim results from this compilation are reported.
... Formation waters from the Amethyst Field (g/L). From Warren & Smalley (1994 Barite and anhydrite locally constitute up to 20 % of the sandstone volume. Sulfur isotopic data indicate a Zechstein source for the sulfur, whereas the Ba (and possibly Ca) was most likely derived from the underlying Carboniferous (Gluyas et al. 1997). ...
... In order to be able to calculate how much water would be needed to transport the amounts of Ba to the Amethyst and Alderley Edge reservoirs, some estimate of the likely amount of Ba in their respective (Carboniferous) source fluids is required. There are only two analyses of formation fluid analyses available for the Carboniferous sections of North Sea oil and gas fields (from the Visund Field) as compiled by Warren & Smalley (1994), but Edmunds (1974) presents 13 analyses of brines in the Coal Measures of the UK Durham coalfield (marginal to the North Sea Basin). The analyses presented by Edmunds (1974) reveal a range of Ba contents from below analytical detection limits (<0.001 g/L), up to a maximum of 4.2 g/L in a brine containing 105 g/L Cl -. ...
... Edmunds (1974) also reported a maximum value of Ba in groundwaters worldwide as 5.53 g/L. The dataset of the Durham coalfield brines and the two Carboniferous brines from the North Sea Formation Fluids Atlas (Warren & Smalley 1994) is not large enough to perform a statisticallymeaningful analysis, but nine of the 13 fluid analyses have a Ba content of less than 0.5 g/L. ...
Published data on the occurrence of pervasive barite (BaSO4) cement associated with faulting in two sandstone reservoir systems, one containing hydrocarbon gas in the southern North Sea, the other bearing metalliferous minerals in the onshore UK Cheshire Basin, have been used to attempt to constrain the amounts of fluid involved in cross-formational fluid flow. Mass balance calculations using plausible estimates of source fluid compositions suggest fluid volumes of at least 3-40 km3 were responsible for barite precipitation. These fluid volumes could have transported a substantial proportion of the metals and hydrocarbons observed in the two reservoir systems.
... To obtain a water composition before any diagenetic reactions had taken place in MSM, the end-products of these reactions (diagenetic minerals) and the present-day formation water chemistry (Warren & Smalley, 1994) were examined. The following assumptions were then made: ...
... Analyses of the present-day formation waters in the Magnus Field (Warren & Smalley, 1994) report an average K + /(Ca 2+ + Mg 2+ ) ratio of 1. The North Sea Piper Field is of comparable age, sedimentary facies, burial depth, formation water salinity and is also in intimate contact with the KCF (the probable CO 2 source), but contained little or no detrital K-feldspar (Piper Field reservoir lithofacies being classified as lithic to sublithic arenites; Burley, 1986). ...
... The North Sea Piper Field is of comparable age, sedimentary facies, burial depth, formation water salinity and is also in intimate contact with the KCF (the probable CO 2 source), but contained little or no detrital K-feldspar (Piper Field reservoir lithofacies being classified as lithic to sublithic arenites; Burley, 1986). Published present-day formation water analyses (Warren & Smalley, 1994) for the Piper Field report an average K + /(Ca 2+ + Mg 2+ ) ratio of 0.1. This order of magnitude difference in K + /(Ca 2+ + Mg 2+ ) ratio supports reactions R1, R2, R3 and R5 as being important in the MSM. ...
A reaction path model was constructed in a bid to simulate diagenesis in the Magnus Sandstone, an Upper Jurassic turbidite reservoir in the Northern North Sea, UKCS. The model, involving a flux of source rock-derived CO2 into an arkosic sandstone, successfully reproduced simultaneous dissolution of detrital K-feldspar and growth of authigenic quartz, ankerite and illite. Generation of CO2 occurred before and during the main phase of oil generation linking source rock maturation with patterns of diagenesis in arkosic sandstones and limiting this type of diagenesis to the earlier stages of oil charging. Independent corroborative evidence for the model is provided by formation water geochemical data, carbon isotope data from ankerite and produced gas phase CO2 and the presence of petroleum inclusions within the mineral cements. The model involves a closed system with respect to relatively insoluble species such as SiO2 and Al2O3 but is an open system with respect to CO2. There are up to seven possible rate-controlling steps including: influx of CO2, dissolution of K-feldspar, precipitation of quartz, ankerite and illite, diffusive transport of SiO2 and Al2O3 from the site of dissolution to the site of precipitation and possibly the rate of influx of Mg2+ and Ca2+. Given the large number of possible controls, and contrary to modern popular belief, the rate of quartz precipitation is thus not always rate limiting.
... The results also have wider implications for the prediction of properties of economic importance based on assumptions about the degree to which diffusive transport of solutes is possible in the residual water in hydrocarbon-saturated rocks. Two specific examples are: (1) The interpretation of resistivity logs to calculate oil and gas saturation and in-place resource volumes, where common practice is to assume one resistivity value (often sampled from the water zone), ignoring potential variations in water composition (Warren and Smalley, 1994); (2) Prediction of diagenetic modification of porosity and permeability in the oil and gas zones, which involves assumptions about whether cementation processes are inhibited by high hydrocarbon saturations, again impacting in-place volume estimates and field development plans (Marchand et al., 2001;Taylor et al., 2010). ...
... Water may be extracted from preserved core samples (e.g., Fjerstad et al., 1993), but this is relatively difficult and costly. A common practice is to use a sample from the water zone, or even from a nearby analogue field (Warren and Smalley, 1994). ...
This study reviews ⁸⁷Sr/⁸⁶Sr depth profiles of formation waters sampled by Sr residual salt analysis (Sr RSA) from >100 oil/gas wells and research sites, including reservoirs with clastic and carbonate host rocks and with gas, oil and water as the continuous fluid phase. Globally, the water data form a smooth trend between low seawater-like ⁸⁷Sr/⁸⁶Sr ratios (∼0.706) at shallow depths and high (∼0.724) ratios in deeply buried rocks, where water-rock interaction dominates.
We test the hypothesis that ⁸⁷Sr/⁸⁶Sr depth profiles in individual wells could be influenced by diffusional mixing processes by developing 1D diffusion mixing equations to simulate compositional patterns through time and comparing them with observed profiles. Different combinations of boundary and initial conditions generate various patterns characteristic of diffusion, including non-steady-state curves relating to incomplete mixing and steady-state patterns (such as vertical or inclined straight lines) where initial heterogeneities have fully mixed. The dataset yielded 193 occurrences of these patterns. Steady-state patterns are more common and longer in water zones, while non-steady-state patterns are more common and longer in oil and gas zones. The detection of diffusional mixing patterns in hydrocarbon-saturated rocks suggests that diffusion is active, although on average a factor of ∼13–18 slower, than in comparable water-saturated rocks.
Pattern generation and equilibration times were modelled for each non-steady-state pattern and compared with the time since reservoir filling with oil/gas, revealing that 90% of them could have been generated since filling, but 60% of them would already have mixed to steady state had the initial compositional heterogeneities arisen during or before reservoir filling. This is critical evidence that at least some of the initial heterogeneities must have arisen, and subsequently partially mixed, after filling; these patterns tend to be short (<40 m, usually <20 m). We conclude that it is essential to consider post-filling processes when interpreting ⁸⁷Sr/⁸⁶Sr depth profiles. This may enable the effects of post-filling processes to be stripped back to reveal larger-scale patterns inherited from oil/gas filling. This approach provides a new framework for identifying and quantifying barriers to fluid communication in petroleum reservoirs, which could be applied to help optimize oil/gas production and water or gas injection, including CO2 injection for enhanced oil recovery and/or subsurface storage.
The evidence for post-fill water-rock interaction and diffusive transport has important implications for porosity/permeability prediction, indicating that key diagenetic processes like quartz cementation may be inhibited by hydrocarbon filling but not stopped altogether. Compositional differences of water within oil/gas zones reveal the folly of using one aquifer water sample as the basis for interpreting water saturations from well resistivity logs for in-place resource estimation. Sr RSA studies may thus be useful in designing water sampling strategies.
... where Sw is the fractional water saturation, a, m and n are the Archie constants (default values: 1, 2 and 2, but modified here to fit SW to as close to 1.00 as possible in the water leg), fRHOB is the porosity determined using the density log (Equation (1)) and Rd is the deep resistivity of the formation. Formation water resistivity values at the temperature of interest, Rw, were taken from Warren and Smalley [17]. The solid part of the rock was split into proportions of shale and sand using normalised gamma log data and the Vshale calculation: ...
... g (8) where rb is the density of the brine, rc is the density of CO2 and g is acceleration due to gravity. Based on formation water compositions for those parts of the North Sea [17], brine density was assumed to be 1.05 g/cm 3 for both Acorn and East Mey sites. The density of CO2 was assumed to be 0.65 g/cm 3 [31]. ...
Petroleum-rich basins at a mature stage of exploration and production offer many opportunities for large-scale Carbon Capture and Storage (CCS) since oil and gas were demonstrably contained by low-permeability top-sealing rocks, such as shales. For CCS to work, there must be effectively no leakage from the injection site, so the nature of the top-seal is an important aspect for consideration when appraising prospective CCS opportunities. The Lower Cretaceous Rodby Shale and the Palaeocene Lista Shale have acted as seals to oil and gas accumulations (e.g., the Atlantic and Balmoral fields) and may now play a critical role in sealing the Acorn and East Mey subsurface carbon storage sites. The characteristics of these important shales have been little addressed in the hydrocarbon extraction phase, with an understandable focus on reservoir properties and their influence on resource recovery rates. Here, we assess the characteristics of the Rodby and Lista Shales using wireline logs, geomechanical tests, special core analysis (mercury intrusion) and mineralogical and petrographic techniques, with the aim of highlighting key properties that identify them as suitable top-seals. The two shales, defined using the relative gamma log values (or Vshale), have similar mean pore throat radius (approximately 18 nm), splitting tensile strength (approximately 2.5 MPa) and anisotropic values of splitting tensile strength, but they display significant differences in terms of wireline log character, porosity and mineralogy. The Lower Cretaceous Rodby Shale has a mean porosity of approximately 14 %, a mean permeability of 263 nD (2.58 × 10−19 m2), and is calcite rich and has clay minerals that are relatively rich in non-radioactive phases such as kaolinite. The Palaeocene Lista Shale has a mean porosity of approximately 16% a mean permeability of 225 nD (2.21 × 10−19 m2), and is calcite free, but contains abundant quartz silt and is dominated by smectite. The 2% difference in porosity does not seem to equate to a significant difference in permeability. Elastic properties derived from wireline log data show that Young’s modulus, material stiffness, is very low (5 GPa) for the most shale (clay mineral)-rich Rodby intervals, with Young’s modulus increasing as shale content decreases and as cementation (e.g., calcite) increases. Our work has shown that Young’s modulus, which can be used to inform the likeliness of tensile failure, may be predictable based on routine gamma, density and compressive sonic logs in the majority of wells where the less common shear logs were not collected. The predictability of Young’s modulus from routine well log data could form a valuable element of CCS-site top-seal appraisals. This study has shown that the Rodby and Lista Shales represent good top-seals to the Acorn and East Mey CCS sites and they can hold CO2 column heights of approximately 380 m. The calcite-rich Rodby Shale may be susceptible to localised carbonate dissolution and increasing porosity and permeability but decreasing tendency to develop fracture permeability in the presence of injected CO2, as brittle calcite dissolves. In contrast, the calcite-free, locally quartz-rich, Lista Shale will be geochemically inert to injected CO2 but retain its innate tendency to develop fracture permeability (where quartz rich) in the presence of injected CO2.
... CO 2 is transported through the aqueous phase during mineralization [18]. The solution composition applied in simulations (Table 1) was selected based on analogous reservoirs in the North Sea [54]. There is currently no data available on detailed water composition from the Johansen Formation. ...
... Dissolution and precipitation are interconnected through these feedback mechanisms [56], and the rate of either will be controlled by the slowest reaction [18]. Carbonate precipitation, most often considered a more rapid reaction compared to silicate dissolution (e.g., [54]), may in some settings provide the rate limiting reaction, such as for low temperature settings [18]. As a first approximation of reactivity and identification of primary reactants, initial geochemical batch simulations including the full mineral assemblage are adequate. ...
Reservoir characterization specific to CO2 storage is challenging due to the dynamic interplay of physical and chemical trapping mechanisms. The mineralization potential for CO2 in a given siliciclastic sandstone aquifer is controlled by the mineralogy, the total reactive surface areas, and the prevailing reservoir conditions. Grain size, morphologies and mineral assemblages vary according to sedimentary facies and diagenetic imprint. The proposed workflow highlights how the input values for reactive mineral surface areas used in geochemical modelling may be parameterized as part of geological reservoir characterization. The key issue is to separate minerals both with respect to phase chemistry and morphology (i.e., grain size, shape, and occurrence), and focus on main reactants for sensitivity studies and total storage potentials. The Johansen Formation is the main reservoir unit in the new full-value chain CO2 capture and storage (CCS) prospect in Norway, which was licenced for the storage of CO2 as of 2019. The simulations show how reaction potentials vary in different sedimentary facies and for different mineral occurrences. Mineralization potentials are higher in fine-grained facies, where plagioclase and chlorite are the main cation donors for carbonatization. Reactivity decreases with higher relative fractions of ooidal clay and lithic fragments.
... Forbes and Gordon Fields (Ketter, 1991[19]), and is 250,000 ppm in the Caister B Field (Ritchie & Pratsides 1993[20]). Warren & Smalley (1994) [21] provide alternative brine salinities of 294,000 and 303,000 ppm for the Esmond and Forbes fields respectively. A brine salinity of 160,000 ppm was used in the present study. ...
... Forbes and Gordon Fields (Ketter, 1991[19]), and is 250,000 ppm in the Caister B Field (Ritchie & Pratsides 1993[20]). Warren & Smalley (1994) [21] provide alternative brine salinities of 294,000 and 303,000 ppm for the Esmond and Forbes fields respectively. A brine salinity of 160,000 ppm was used in the present study. ...
Injecting CO2 in to the subsurface for safe storage of CO2 the pressure propagates far away from the injection point and this can be a potential problem if the overpressure extents to neighbouring subsurface activities or potential leakage pathways. For structural closure trap configurations the CO2 plume is captured within the local structural closure but the pressure footprint is on a more regional scale.
This rise the question on, how large the storage complex needs to be for any individual storage operations and how large an area monitoring activities have to cover. The EC CCS guidance document addresses the issues with statements on competitions between subsurface operations but returns no absolute values.
Pressure modelling of CO2 injection process with state of the art reservoir simulation tools is challenges by use of realistic model boundary conditions in order to model a realistic pressure level. Combined use of models on a site scale and on a regional scale can instruct how boundary conditions are set-up for a site scale model.
Pressure management through pressure release wells could be an option to mitigate undesirable over-pressure developments. For local structural closures the pressure release wells can be placed outside the closure hereby mitigate the overpressure without introducing a potential leakage by drilling inside the trap.
The paper addresses the issue of selecting model boundary conditions and modelling mitigation of pressure development by use of a large regional model with local structural traps in the Bunter Sandstone Formation in the UK Southern North Sea.
... Analyses of the present day formation waters in the Magnus Field ( Warren and Smalley, 1994) report an average K /(Ca 2 Mg 2 ) ratio of 1. The Piper field (of comparable age, sedimentary facies, burial depth, formation water salinity to Magnus and also in inti- mate contact with the KCF), contained little or no detrital K-feldspar. ...
... The Piper field (of comparable age, sedimentary facies, burial depth, formation water salinity to Magnus and also in inti- mate contact with the KCF), contained little or no detrital K-feldspar. Published present day formation water analyses ( Warren and Smalley, 1994) for Piper report an average K /(Ca 2 Mg 2 ) ratio of 0.1. This order of magnitude difference in K / (Ca 2 Mg 2 ) ratio supports the proposed reactions. ...
... Other likely sources of fluids with high 6180 compositions are the sedimentary basins flanking the Cornubian peninsula. Bjorlykke et al. (1986), Burley & MacQuaker (1992), Egeberg & Aagaard (1989) and Warren & Smalley (1994) provide 6180 compositions of present-day sedimentary brines from the North Sea ranging between -4%o and +10%o. ...
... In terms of the inferred water ~SD compositions, candidate fluids include present-day meteoric waters (-28%0 to -40%o, Edmunds et al. 1984), meteoric water in areas of extreme evaporation conditions (Faure 1986), as well as brines from sedimentary basins (0%0 to -45%o, Bjorlykke et al. 1986;Burley & MacQuaker 1992;Egeberg & Aagaard 1989;Warren & Smalley 1994). Psyrillos et al. (1998) show that the granite kaolinization may result from a range of fluids undersaturated with respect to carbonates and sulphates, provided that the initial fluid loga(K+/H +) is lower than approximately 1.8 at 50~ 2.0 at 75~ and 2.1 at 100~ This excludes waters from carbonate aquifers and meteoric waters from areas with extreme evaporative conditions, leaving highly modified meteoric waters and/or sedimentary brines from siliciclastic aquifers as candidate fluids. ...
A new genetic model is proposed for the formation of the St Austell kaolin deposits, incorporating geological, isotopic, paragenetic and microthermometric evidence from kaolin~luartz veins combined with a reconstruction of the thermal evolution of the Cornubian pluton during the Mesozoic. Fluid inclusions in quartz, paragenetically associated with kaolin, document that the kaolinization took place at temperatures between 50 ~ and 100 ~ indicating that the kaolinization is a low-temperature hydrothermal event coincident with the oil generation window.
Kaolinization occurred prior to the unroofing of the pluton, during the Late Jurassic to Early Cretaceous. The kaolinization is thus contemporary with the major Early Cretaceous uplift that affected the Cornubian massif as a consequence of rifting in the offshore Western Approaches. Geological, isotopic and geochemical considerations argue strongly against the involvement of unmodified meteoric waters in the kaolinization process. The most plausible fluid types for the kaolinization are either basinal brines expelled from Permo-Triassic sediments of the adjacent offshore Plymouth Basin, or highly evolved meteoric waters that circulated through the sediments enclosing the pluton. The kaolinization process converted large volumes of fractured granite to a porous quart~kaolin rock matrix.
... Figure 8 shows porewater analyses from Jurassic oilfield sandstones of the UK northern and central North Sea for the depth range of 2.8À5.5 km, the same range for which (uncontaminated) illite analyses are available. There is no increase in the concentration of K or K/H in porewaters with increasing burial depth in the UK northern North Sea but an increase, or at least an increase in the maximum values, in the UK central North Sea (data from Warren & Smalley, 1994). Porewaters in oilfield sandstones in the Norwegian sector of the North Sea show no changes (Egeberg & Aagaard, 1989); this area has geology which is closely related to the UK northern North Sea. ...
... Porewater K 2 O and log(K 2 O/H) for the Jurassic oilfield sandstones of the northern and central North Sea versus burial depth (data fromWarren & Smalley, 1994) for the same depth range for which illite compositional data are available. There is no significant change in K 2 O or K 2 O/H in the northern North Sea, but an increase in the maximum values of both K 2 O and K 2 O/H in the central North Sea with increasing burial depth. ...
It has been previously reported that late diagenetic fibrous illite, separated out from oilfield sandstones for dating by the K-Ar method, has systematically shown an increasing K-content with burial depth in the UK northern and central North Sea. This is surprising as fibrous illite is believed to form rapidly, in response to a geological event such as oil charging, and to retain its composition during subsequent burial. If the composition of the illite is related to present-day conditions, rather than the conditions of initial formation, then argon loss may have occurred, making K-Ar ages of questionable validity. Variations in crystal chemistry of the illite and their fundamental particle size and shape (length/width) distribution suggest alteration of the illite from the time of formation. The extent to which K-Ar ages of illite might need to be re-interpreted as a result of this post-formation alteration is not quantifiable at present; however there is evidence to suggest that the ages may be interpreted in terms of burial models involving both crystal nucleation and growth, and that a high proportion of Ar within the crystals may be retained during post-growth recrystallization.
... Analyses of the present day formation waters in the Magnus Field (Warren and Smalley, 1994) report an average K ϩ /(Ca 2ϩ ϩ Mg 2ϩ ) ratio of 1. The Piper field (of comparable age, sedimentary facies, burial depth, formation water salinity to Magnus and also in intimate contact with the KCF), contained little or no detrital K-feldspar. ...
... The Piper field (of comparable age, sedimentary facies, burial depth, formation water salinity to Magnus and also in intimate contact with the KCF), contained little or no detrital K-feldspar. Published present day formation water analyses (Warren and Smalley, 1994) for Piper report an average K ϩ /(Ca 2ϩ ϩ Mg 2ϩ ) ratio of 0.1. This order of magnitude difference in K ϩ / (Ca 2ϩ ϩ Mg 2ϩ ) ratio supports the proposed reactions. ...
The Upper Jurassic sub-arkosic turbidite sandstones of the Magnus oil field, UK North Sea, are dominated by quartz, ankerite and kaolinite cements that all grew immediately prior to, and during, the early stages of oil-filling. The sandstones have no evidence of siliceous bioclasts or pressure dissolution yet contain ≤15% quartz cement with relatively more in the water leg than in the oil leg. Petrographic analysis revealed that the sandstones have undergone major K-feldspar alteration, especially in the water leg. XRF whole-rock data show that sandstones have uniform Si/Si+Al throughout the reservoir indicating that silica is not imported into the sandstone during quartz cementation. Carbon isotope data from the ankerite require an influx of organically derived CO2. Geochemical modelling of a CO2-influx into arkosic sandstone suggests that quartz, ankerite and kaolinite cements are likely to be genetically related. Reaction of K-feldspar with water at low pH will produce quartz and kaolinite. Low pH resulted from CO2-influx and was maintained through ankerite precipitation. The reaction led to bulk loss of potassium (most likely to the surrounding mudrocks). K-feldspar dissolution is thus the result of an influx of externally (source rock) derived CO2 although the silica in the quartz cement is derived internally in the sandstone. While there is no need to invoke large scale-import of silica-laden waters, quartz cementation is the result of fluid influx.
... This makes the BSF hydrostatically pressured with variable amounts of brine of variable salinity and density. Brine salinities and brine densities were investigated by Ritchie and Pratsides [377] and Warren and Smalley [382]. Typical values for fields are: 294000 ppm and 1.211 g cm -3 (Esmond); 303000 ppm and 1.220 g cm -3 (Forbes); 180000 ppm and 1.119 g cm -3 (Orwell); and 250000 ppm and 1.174 g cm -3 (Caister B). ...
... The Triassic evaporites in the Wessex Basin are halite-rich, continental evaporites with no sylvite or other signs of extreme marine evaporation. (b) Water compositional data from the North Sea Basin with the main evaporite being the sylvite-bearing Permian Zechstein (Egeberg and Aagaard 1989;Ziegler et al. 2001;Warren and Smalley 1994). The North Sea data can be explained by a combination of seawater dilution by meteoric water and one or more of (i) meteoric dissolution of halite-dominated evaporites that contain 20% sylvite (or other Br-rich potash salts), (ii) the formation waters represent the remnants of evaporatively concentrated seawater, (iii) concentration by diagenetic hydration reactions (Fig. 4.4) with either addition of Br-from organic sources (Fig. 4.13) or preferential incorporation of Cl in neoformed clay minerals. ...
The full range of processes capable of influencing halogen concentrations in sediments, sedimentary rocks, and formation waters and other fluids involved in diagenetic reactions have been investigated. Chloride and Br⁻ are typically assumed to be conservative in sedimentary and diagenetic systems since they are considered to be independent of silicate, carbonate, sulphate, sulphide, or oxide diagenetic processes. Chloride distribution in sedimentary systems is controlled by variable degrees of seawater evaporation; seawater dilution by meteoric water, freshwater evaporation in arid continental basins; seawater freezing; evaporite dissolution; seawater concentration by silicate diagenetic hydration reactions in the sediment column; seawater dilution by diagenetically-produced water associated with overpressure build-up; and membrane filtration through low permeability rocks. There are circumstances under which Br may not be a conservative element when compared to Cl. These include hydration reactions, which may lead to increasing Cl⁻ and Br⁻ concentrations but slightly higher Cl/Br ratios; evaporative concentration, which may lead to loss of Br⁻ by atmospheric ozonation processes; incongruent dissolution of Br-poor halite; dissolution of Br-enriched potash facies evaporites; breakdown of Br-bearing organic matter; or retarded membrane filtration of Br compared to Cl. Water geochemical data from oil and gas fields have been collated and compared with a range of likely controlling processes. Chloride and Br⁻ concentrations in formation water are enormously variable with the most important controls being dilution of seawater by meteoric water; evaporative concentration (of seawater or continental waters); dissolution of halite- and/or potash-bearing evaporites; diagenetic hydration reactions; and diagenetic dehydration reactions. Dissolution of mixed halite-potash facies evaporites by meteoric water can explain the huge range of Cl/Br ratios found in formation waters. High Br⁻ concentrations in deeply buried formation waters are typically assumed to represent the residue of extreme evaporation of seawater although here it is shown that they can also be the result of the dissolution of Br-enriched, potash-bearing evaporites. Fluoride is non-conservative in formation waters and its concentrations are typically low since this element is incorporated in minerals, following alteration and diagenesis, such as fluorite, apatite, and clay minerals. Iodide is also non-conservative and is found at relatively high concentrations in some formation waters due to the breakdown of I-enriched and organic-bearing sedimentary rocks. The patterns of halogen concentration in sedimentary formation waters can be of great significance since they reveal much about the fluid flow history of the basin in general and the oil or gas field in particular.
... Hence, it is the source of iron and not the amount of hydrogen sulphide in the produced fluids that most commonly determines the amount of scale formed 1 . Some reservoirs contain iron minerals and produced waters contain variable levels of Fe 2+ concentrations 2 . In other cases, it is corrosion processes of various types that are the main iron source for the precipitation of iron sulphide scale. ...
In order to implement an effective iron scale mitigation strategy, operators first need to identify the main source of iron in the system. Establishing the main source of Fe2+ in higher temperature sour wells where iron sulphide and iron carbonate are formed can be problematic. Many fields do not have reliable formation water composition and the analysis of produced water often does not allow us to draw clear conclusions when corrosion and scale formation occurs in the well. This work describes a method to predict the “maximum dissolved iron” (MDI) concentration in a reservoir/production system. The MDI is the amount of dissolved iron potentially present at equilibrium either in a reservoir or in the production system; for example, we will show that the MDI can be quite different in a carbonate reservoir and in the production system. Using this concept (MDI), we aim to identify if iron deposits may be formed from naturally occurring Fe2+ (present in formation fluids) or solely from corrosion processes and/or external sources. The results presented in this paper include a sensitivity study on the effects of dissolved CO2 and H2S concentrations, temperature, calcium levels and salinity on the MDI. Finally, results from two field cases are presented where one is a sour gas/condensate field and the other is a black oil reservoir.
Key words: Iron sulphide, iron source, sour corrosion, formation iron, souring, scale prediction, carbonate reservoir.
... The injection of gas into sub-seabed aquifers or depleted hydrocarbon fields could lead to the displacement of fluids low in oxygen and highly enriched in ions, which, if they reached the seabed, could bring about a strong change in environmental conditions. The majority of deep aquifers in the North Sea are filled with high salinity formation (Warren and Smalley, 1994;Evans et al., 2003), in some cases in excess of 300 psu, a value similar to that of the Dead Sea (≈340 psu). If these reached the seabed, they could cause an up to ten-fold increase in local salinity, thus representing a potentially severe osmotic shock to organisms. ...
... However, during shallow burial, sulfate-reducing bacteria remove much of the original dissolved sulfate present in marine pore water. Deep subsurface waters typically have low sulfate concentrations, with sulfate (SO 4 )/Cl ratios much less than those of seawater; some exceptions are formation waters associated with SO 4 (e.g., anhydrite) deposits (Warren and Smalley, 1994). ...
Schlumberger's modular dynamics tester (MDT) tool was used to test 10 Miocene sands in the Tubular Bells deep water oil field, offshore Gulf of Mexico, United States. Nine sands from true vertical depths of 19,999-26,464 ft (6096-8066 m) were sampled from a single well and another deeper sand (29,075 ft [8,862 m]) from a second well. Using ion and strontium, oxygen, and hydrogen isotopic analysis, the nine MDT water samples were demonstrated to be mostly formation water. The sample in the second well from 29,075 ft (8862 m) is filtrate, based on its oxygen and hydrogen isotopic composition (-4.10 parts per thousand and -26.3 parts per thousand, standard mean ocean water [SMOW]). Insufficient water was recovered for ionic analysis, which made the isotopic analysis even more important to help document the origin of the water in what appears to be a hydrocarbon-charged interval. Using a combination of chemical and isotopic analyses, it is concluded that only two of the sands are possibly in fluid communication or separated by baffles. The other sands are each in separate fluid compartments. The salinity (total dissolved solids) of the formation waters decreases with depth and distance from the salt and ranges from approximately 39,000 to more than 288,000 mg/L. The formation waters have oxygen and hydrogen isotopic compositions ranging from +3.19 parts per thousand to +4.52 parts per thousand and -16.1 parts per thousand to -19.4 parts per thousand, respectively (SMOW). Bromide-chloride systematics indicate that the formation waters are mixtures of normal seawater and seawater that was evaporated to and probably beyond halite saturation. The evaporite water is sourced from the deeper Jurassic section (Louann Salt) and likely came up along the salt sediment interface along faults and fractures associated with emplacement of the salt stock and canopy. The formation waters were subsequently enriched in chloride and sodium to varying degrees by dissolution of the diapiric salt. Strontium isotopes are compatible with mixing of highly concentrated (evaporative) Jurassic seawater with relatively low Sr-87/Sr-86 ratios and much less concentrated (almost seawater salinity) pore water with more radiogenic strontium, the latter derived from silicate reactions during burial diagenesis. Short-chain organic acids are present in high concentrations (>1000 mg/L) along with the organophilic ions boron and iodide. The concentrations of boron, iodide, and organic acids do not correlate with salinity. Boron and iodide show a strong positive relationship with each other and a less strong, but positive, relationship with organic acid concentrations. Boron and iodide are nearly twice as concentrated in waters of oil-bearing sands than in water-bearing sands and appear to be indicators of hydrocarbon proximity. One water-bearing sand has concentrations of boron and iodide as high as those seen in oil-bearing sands, possibly suggesting an updip oil accumulation.
... g/L. These compositions are well within the usual range encountered in co-produced waters from conventional hydrocarbon reservoirs worldwide, including in the UK (e.g., Warren & Smalley 1994), and indeed with natural saline springs and geothermal waters encountered in northern England . However, like all of these other natural waters, their very salinity renders them undesirable for mixing with water in fresh water aquifers, lakes, streams or rivers (cf. ...
Development of shale gas by hydraulic fracturing (‘fracking’) is opposed by campaigners who propose ( inter alia ) that freshwater aquifers could be polluted by upward migration of fractures and any fluids they contain. Prima facie hydrogeological analysis of this proposition has been undertaken. For it to occur, two conditions must be satisfied: (i) sufficient hydraulic interconnection (i.e., a continuous permeable pathway); and
(ii) a sustained driving head, oriented upwards.
With regard to (i), shale gas developers have a major vested interest in avoiding creating such hydraulic connection, as it would result in uneconomically excessive amounts of water needing to be pumped from their wells to achieve gas production. In relation to (ii), nominal upward hydraulic gradients will typically only be developed during fracking for periods of a few hours, which is far too brief to achieve solute transport over vertical intervals of one or more kilometres; thereafter, depressurisation of wells to allow gas to flow will result in downward hydraulic gradients being maintained for many years. The proposition is therefore found to be unsupportable. Albeit for contrasting motivations, developers and environmental guardians turn out to have a strong common interest in avoiding inter-connection to aquifers.
A powerful illustration of the potential long-term effects of fracking is provided by the hydrogeological history of underground coal mining in the UK. Where large-scale mining proceeded from the surface downwards, major hydraulic inter-connection of shallow and deep zones resulted in widespread water pollution. However, where new mines were developed at depth without connections to shallow old workings (as in the Selby Coalfield, Yorkshire), complete hydraulic isolation from the near-surface hydrogeological environment was successfully maintained. This was despite far greater stratal disruption and induced seismicity than shale gas fracking could ever produce. The lesson is clear: without hydrogeological connectivity to shallow aquifers, shale gas fracking per se cannot contaminate shallow ground water.
... The injection of gas into sub-seabed aquifers or depleted hydrocarbon fields could lead to the displacement of fluids low in oxygen and highly enriched in ions, which, if they reached the seabed, could bring about a strong change in environmental conditions. The majority of deep aquifers in the North Sea are filled with high salinity formation (Warren and Smalley, 1994;Evans et al., 2003), in some cases in excess of 300 psu, a value similar to that of the Dead Sea (≈340 psu). If these reached the seabed, they could cause an up to ten-fold increase in local salinity, thus representing a potentially severe osmotic shock to organisms. ...
This paper reviews research into the potential environmental impacts of leakage from geological storageof CO2since the publication of the IPCC Special Report on Carbon Dioxide Capture and Storage in 2005. Possible impacts are considered on onshore (including drinking water aquifers) and offshore ecosystems.The review does not consider direct impacts on man or other land animals from elevated atmospheric CO2levels. Improvements in our understanding of the potential impacts have come directly from CO2storageresearch but have also benefitted from studies of ocean acidification and other impacts on aquifers andonshore near surface ecosystems. Research has included observations at natural CO2sites, laboratory andfield experiments and modelling. Studies to date suggest that the impacts from many lower level fault-or well-related leakage scenarios are likely to be limited spatially and temporarily and recovery may berapid. The effects are often ameliorated by mixing and dispersion of the leakage and by buffering andother reactions; potentially harmful elements have rarely breached drinking water guidelines. Largerreleases, with potentially higher impact, would be possible from open wells or major pipeline leaks butthese are of lower probability and should be easier and quicker to detect and remediate.
... The injection of gas into sub-seabed aquifers or depleted hydrocarbon fields could lead to the displacement of fluids low in oxygen and highly enriched in ions, which, if they reached the seabed, could bring about a strong change in environmental conditions. The majority of deep aquifers in the North Sea are filled with high salinity formation (Warren and Smalley, 1994;Evans et al., 2003), in some cases in excess of 300 psu, a value similar to that of the Dead Sea (≈340 psu). If these reached the seabed, they could cause an up to ten-fold increase in local salinity, thus representing a potentially severe osmotic shock to organisms. ...
... The effect of salinity was disregarded in this study due to lack of formation water samples. Data from over-and underlying formations indicate low salinities (Warren and Smalley, 1994), and a fluid inclusion measurement indicated negligible salt content (Gassnova, 2012). Previous studies have assumed salinities in the order of 5% (Eigestad et al., 2009) to 10% (Wei and Saaf, 2009). ...
... These oxygen isotopic values have evolved from an original estimated meteoric δ 18 O value of-5‰. Formation waters in sedimentary basins are known to become enriched in 18 O isotope and total dissolved solids due to sediment-water interaction during progressive burial (e.g., Warren and Smalley, 1994). Carbonate cementation has thus continued throughout eodiagenesis and mesodiagenesis. ...
The reservoir quality of fluvial sandstones of the Upper Jurassic Boipeba Member, Reconcavo basin, northeastern Brazil, is highly heterogeneous and controlled by eodiagenesis under semiarid climate, mesodiagenesis during burial to a depth of 3500 m, and telodiagenesis due to local uplift. Eodiagenesis resulted in mechanical compaction, calcite cementation, clay infiltration, and limited grain dissolution, whereas mesodiagenesis resulted in the precipitation of calcite cement and quartz overgrowths, intergranular quartz-grain dissolution, chloritization and illitization of smectite, and albitization of feldspars. Sandstones continuously buried at maximum burial depths of about 1600 m (T = 65°C) since 125 Ma display a relatively greater degree of mesogenetic modifications and, on average, poorer reservoir quality than sandstones that were buried deeper (2100 m, T = 75°C) prior to uplift, but only since 13 Ma. Uplift, which affected the sequence along the western border of the basin, has resulted in telogenetic dissolution of framework silicates and formation of kaolinite. Relatively good reservoir quality in the deeply buried sandstones occurs when (1) the grains are coated with a thin layer of chloritized infiltrated smectite, (2) there is little or no pseudomatrix, and (3) there are widely scattered patches of eogenetic calcite cement that supported the framework of sandstones against compaction.
... This shows that the experiments were done with the Mg concentration that is found in the natural setting, and d) Mg concentration as function of pH also displays that the pH of the nutrient solutions used in this study confirmed (red rhombohedra) that the experiments were operated in the natural setting condition. The north sea formation water chemistry data to construct the plots in Figure 2 were taken from North Sea Formation Waters Atlas, Geological Society Memoir No. 15 (Warren and Smalley, 1994). (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.) ...
Laboratory experiments were performed to investigate high-temperature (100 to 150°C) authigenic formation of clay coatings (smectites, chlorites) on clean feldspar and quartz surfaces. Artificial formation waters were used, with Mg-concentrations in the range of North Sea brines. Experiments were run for 21-50 days in brines composed of magnesium chloride and sodium carbonate adjusted to circum-neutral pH. The experiments suggest that the silica activity is the main factor determining if grain coating smectites or chlorite form. The clay minerals form easily on both clean quartz and feldspar surfaces, but chlorite coatings were formed only on feldspar surfaces while smectite coatings were formed on both feldspar and quartz. The chlorite morphology varies between honeycomb, edge-to-face and rosette patterns, while all smectite formed with honeycomb-like textures. The clay coatings produced in this study are morphologically similar to naturally occurring diagenetic clay minerals. In natural sediments and sedimentary rocks, the formation of clay coatings is promoted by pre-existing clay drapings on mineral grains. The growth substrates used in this study were not coated with such a natural precursor materials. This suggests that the nucleation of clay coatings in nature may be possible on clean quartz and feldspar surfaces, but pre-existing clay minerals may impact the allowed levels of supersaturations and thereby the formation of the grain-coating phases.
... Formation water in Corrib has very high salinity of 27% NaCl equivalent by mass. It also has high potassium and calcium concentrations and is broadly similar to formation water from Southern North Sea gas fields, where the salinity has been derived from dissolution of Zechstein evaporites (Warren & Smalley, 1994). ...
The Triassic Sherwood Sandstone in the Corrib Field, Slyne Basin west of Ireland on the European continental margin, is a dry gas reservoir with a Mercia mudstone top-seal. Petrographic analysis combined with X-ray diffraction, stable isotope, fluid inclusion and core analysis have been used to assess: timing of growth and origin of mineral cements, whether sandstone diagenesis involved mass flux, the controls on reservoir quality and how reservoir quality is likely to vary in more deeply buried sections. Depositional and early diagenetic characteristics of the Sherwood in Corrib are typical of a semi-arid fluvial environment, containing groundwater of meteoric origin. Early diagenesis included the development of copious dolomite cement, in the form of dolocrete, as well as the formation of abundant clay while less volumetrically important, grain-coating haematite and K-feldspar cement also grew. Burial diagenesis witnessed the initial growth of minor chlorite and albite. Quartz overgrowths and ankerite followed and are the most important burial cements growing over a temperature interval between 100 and 1165 °C. Albite commenced growth at about 90 °C, quartz cement at 100 °C and ankerite at 110 °C. These cements reached the zenith of their development at 105–110 °C for albite, 125–130 °C for quartz and 135–145 °C for ankerite. Siderite and anhydrite are relatively minor, late-stage cements. The formation water has been consistently highly saline during burial and, in terms of mineral cement-derived oxygen stable isotope values, is likely to be a diagenetically evolved version of the initial depositional water suggesting long-term stagnation of the pore-fluids. The diagenetic reactions that formed burial cements all seem to be essentially isochemical including the ankerite that has carbon isotope characteristics of the cannibalisation of dolocrete. Reservoir quality is mainly controlled by early diagenetic dolomite and clay although grain size is also important because only sandstones with >200 μm grain size have >50 md permeability. Both shallower and deeper sections than Corrib may have similar porosity and permeability since temperature-dependent diagenetic controls on reservoir quality, e.g. quartz and illite cement, are peripheral.
... H 2 S data are here presented in terms of standard cubic feet (scf) of H 2 S per barrel of oil to remove the variable dilution of sulphide by hydrocarbon gas. Formation water data have been taken from Warren and Smalley (1994). FIV and XRD analysis methods and data treatment were reported in Barclay et al. (2000) and include fastidious sample cleaning followed by crushing and analysis of volatiles in mass spectrometers. ...
H2S in North Sea basins is broadly limited to the Central and Wytch Ground Grabens where it occurs at concentrations of up to 20,000 ppm. H2S is likely to be due to thermochemical sulphate reduction occurring between sulphate enriched waters, derived from Zechstein evaporites, and oil. Although the sulphur content of oil decreases with increasing reservoir temperature, H2S and the oil-sulphur content are not inversely correlated: H2S cannot have originated from S-compound cracking in oil. There is a broad correlation between the sulphur isotope value of oil and H2S concentration suggesting that TSR-H2S has been incorporated into the oil. H2S is only notably enriched in oil fields at about 120 degreesC proving that thermochemical sulphate reduction is likely (and bacterial reduction unlikely). H2S is highly enriched only in Upper Jurassic, clean quartz arenites suggesting that in more normal subarkosic and sublithic sandstones, TSR-H2S is scrubbed by Fe-minerals producing late-stage pyrite cement, common in North Sea reservoirs.
... There is some evidence that high salinity fluids are more compressible than low salinity fluids (Potter and Brown, 1977), but this effect is likely to be minor. Data from a compilation of North Sea formation waters by Warren and Smalley (1994) show that a similar weak negative correlation between salinity and depth (and salinity and temperature) exists in present day formation waters in Middle Jurassic (Brent Group) reservoirs (Figure 4). The salinity-Th variations in fluid inclusions could therefore merely record trends in Middle Jurassic formation water salinity and temperature which have remained largely unchanged since the Late Cretaceous. ...
... Formation water in Corrib has very high salinity of 27% NaCl equivalent by mass. It also has high potassium and calcium concentrations and is broadly similar to formation water from Southern North Sea gas fields, where the salinity has been derived from dissolution of Zechstein evaporites (Warren & Smalley, 1994). ...
The Triassic Sherwood Sandstone in the Corrib Field, Slyne Basin west of Ireland on the European continental margin, is a dry gas reservoir with a Mercia mudstone top-seal. Petrographic analysis combined with X-ray diffraction, stable isotope, fluid inclusion and core analysis have been used to assess: timing of growth and origin of mineral cements, whether sandstone diagenesis involved mass flux, the controls on reservoir quality and how reservoir quality is likely to vary in more deeply buried sections. Depositional and early diagenetic characteristics of the Sherwood in Corrib are typical of a semi-arid fluvial environment, containing groundwater of meteoric origin. Early diagenesis included the development of copious dolomite cement, in the form of dolocrete, as well as the formation of abundant clay while less volumetrically important, grain-coating haematite and K-feldspar cement also grew. Burial diagenesis witnessed the initial growth of minor chlorite and albite. Quartz overgrowths and ankerite followed and are the most important burial cements growing over a temperature interval between 100 and 1165 °C. Albite commenced growth at about 90 °C, quartz cement at 100 °C and ankerite at 110 °C. These cements reached the zenith of their development at 105–110 °C for albite, 125–130 °C for quartz and 135–145 °C for ankerite. Siderite and anhydrite are relatively minor, late-stage cements. The formation water has been consistently highly saline during burial and, in terms of mineral cement-derived oxygen stable isotope values, is likely to be a diagenetically evolved version of the initial depositional water suggesting long-term stagnation of the pore-fluids. The diagenetic reactions that formed burial cements all seem to be essentially isochemical including the ankerite that has carbon isotope characteristics of the cannibalisation of dolocrete. Reservoir quality is mainly controlled by early diagenetic dolomite and clay although grain size is also important because only sandstones with >200 μm grain size have >50md permeability. Both shallower and deeper sections than Corrib may have similar porosity and permeability since temperature-dependent diagenetic controls on reservoir quality, e.g. quartz and illite cement, are peripheral.
... 10). The 18 O difference between CO 2 and water at equilibrium is 26‰ at 130C (Warren & Smalley 1994). This infers a 18 O value for pore water in isotopic equilibrium with CO 2 at 4323 m of 14.9‰ (40.9‰ [ 18 O CO 2 ] – 26‰). ...
Block 35/1 with the dry Sturlason structure, is located on the northernmost part of the Marflo Ridge in the Norwegian part of the Northern North Sea. It is separated by deep faults from the Sogn Graben to the east and the Marulk Basin to the west. The 35/1-1 well proved only minor shows of gas and oil in the well.
The Sturlason structure comprises a series of upthrown fault blocks in a structurally complex area. The well-established Brent Formation carrier and reservoir sandstone has shaled out this far north and the stratigraphically deeper Lower Jurassic Statfjord Formation and Triassic Lunde Formation sandstones were, in the exploration model, suggested as both carrier beds and reservoirs. The prolific Upper Jurassic Draupne (Type II organic matter, OM) and Heather (Type II/III OM) Formation source rocks were, based on seismic data, interpreted to be absent or thin over the prospect, thus implying lateral migration for filling the structure with petroleum. Structural back-stripping suggests that part of Block 35/1 was sub-aerially exposed as an island during deposition of the Upper Jurassic source rocks. This may have impacted the quality and nature of the fringing organic material due to a more oxic environment and a greater influx of Type III organic matter.
The geochemical analyses were hampered by contamination from the use of oil-based mud (C 13–23 range hydrocarbons) while drilling. Despite this, traces of true indigenous C 4–10 and C 25+ range hydrocarbon are demonstrated. These results suggest presence of an evaporative condensate and heavy oil fraction originating from a source rock related to a hypersaline carbonate depositional environment.
A buoyancy-driven fluid flow study, without taking faults into account, shows the difficulty in charging the prospect and clearly suggests the presence of sealing faults. The latter are also substantiated by a separate fault-seal analysis. Traps in flanking areas could, however, receive petroleum. Gas is also interpreted to be present in shallower sediments over the eastern flank of the Sturlason structure.
The annual demand for lithium for low-carbon technologies applications has been trading exponentially forward, 965% more in 2050 than the quantity demanded in 2017. In the current chain of demand, there is a necessity for continuous lithium production from both conventional sources (i.e., salt lakes and rock minerals) as well as the incorporation of novel extraction sites from alternative brine resources such as Oilfield and Geothermal. In the present paper, the lithium potentiality of the North Sea is evaluated with fields in the Central-East and Southern-West reaching the highest regional concentration of 40 ppm. Those include oilfields such as Montrose, Arbroath, Ula, Nelson, Brisling, Gyda, Ekofisk and Bream, as well as gas fields such as the Esmond, Anglia, Lemman, Ann, and Viking, with the possibility of brine enrichment extending itself even to shallow waters fields around the Groningen region. To experimentally evaluate the potential extractability of lithium from those oilfield brine resources in the North Sea, ion-sieve adsorbents (Li1.6Mn1.6O4) were prepared from commercially available LiMnO2 and formed into three different ion-exchange membranes. The foam had the best performance out of those structures, displaying a higher and much stabler powder insertion capacity compared to granular and flat sheet membranes, which registered significant material loss. At an optimum polymeric concentration of 10% and MNO/PVA ratio of about 50%, the foam membrane had the highest theoretical extraction capacity of 9.94 mg/g, followed by granular and flat sheet, with 7.36 and 7.24 mg/g, respectively. Those membranes had good selectivity forward lithium ion in the presence of other competing cations when used on synthetic oilfield brine with concentration mimicking that of Buchan field, being able to efficiently recover 18.4% (foam), 17% (granular), and 14.37% (flat sheet) of lithium. However, the recovery capacity was increased up to 50% when non-formed HMO powder was used, with selectivity in the following decreased order of affinity, Li+ > Mg2+ > Na+ > Ca2+ > K+. The powder recoverability raises the lithium production prospect from North Sea brine to about 26.2 kg per day with an estimated market value of 1834 USD for the produced quantity.
Routine measurements of reservoir pressure variation with depth can detect pressure discontinuities indicative of barriers to vertical fluid movement. This study investigates how pressure data can be augmented by detailed profiles of formation water ⁸⁷Sr/⁸⁶Sr ratio to determine the precise location and cause of such barriers, and by C-O-Sr isotope analysis of carbonate cements to determine the duration over which the barrier has persisted. The study focuses on the clastic Hugin Formation reservoir in the Langfjellet Oil Discovery (Norwegian North Sea). Here, pressure data indicated a barrier somewhere within a 25 m depth interval. Formation water ⁸⁷Sr/⁸⁶Sr was measured with high spatial resolution by extraction from core samples using the residual salt analysis (RSA) method. This revealed three homogeneous populations of water separated by a small step in ⁸⁷Sr/⁸⁶Sr over a 7 m interval containing coal and shale layers, and a very large step in ⁸⁷Sr/⁸⁶Sr over a 1.2 m interval corresponding to a thin coal and shale layer situated below a major flooding surface. The latter is the main candidate for the pressure barrier. Modelling confirmed that this inferred pressure barrier also greatly retards Sr diffusion.
Carbonate cements occur disseminated throughout the reservoir and in several heavily-cemented zones. Oxygen isotope-derived temperatures indicate that these formed in two episodes: (1) Pre-compactional, precipitated shortly after deposition in the zone of bacterial methanogenesis (∼30ºC, ∼200 m depth, ∼162 Ma); (2) Post-compactional incorporating thermal decarboxylation-derived carbon (∼90ºC, ∼2500 m depth, ∼46 Ma). Carbonate ⁸⁷Sr/⁸⁶Sr data reveal the same compositional populations present in the current formation water to be present in both cement generations. The water compositional stratification must thus have been present when the early and late cements precipitated, down till today. The persistence of a compositional step for most of the geological history of the rocks confirms the presence of a major fluid communication barrier. The Sr RSA data show invariant water composition across the heavily carbonate cemented intervals, implying no barrier effect.
The combination of pressure data (to identify pressure barriers), Sr RSA (to add spatial resolution) and Sr-C-O isotopes of carbonates of different ages (to add a time dimension) is useful for identifying major long-term fluid communication barriers and differentiating them from smaller, less effective or shorter-term features. The method has applications for identifying seals in exploitation of petroleum and water resources, and underground storage of CO2 and radioactive waste.
The salinity of pore waters in petroleum reservoir rocks, including shale and tight reservoirs, varies from ~1000 to >400,000 mg/L TDS. Detailed chemical and isotopic data for >115,000 produced‐water samples, listed in our USGS Database, show the waters are of meteoric, marine connate, or mixed origin. During diagenesis, waters of deposition evolve to Na–Cl‐, Na–Cl–CH3COO‐, or Na–Ca–Cl‐type waters by a combination of several processes: (i) dissolution of halite; (ii) diffusion and advection near salt domes; (iii) reflux and incorporation of bittern water; (iv) dissolution, precipitation, and transformation of minerals; (v) interactions with shales that behave as geologic membranes; and (vi) interactions with petroleum, solid organics, and bacteria. Geochemical data of pore waters in shale and tight reservoirs have been reported in only a few detailed studies, but we have received such data from oil companies for ~15,000 samples of “flowback” and produced waters. The salinities and compositions carry large uncertainties, especially for the “flowback” samples that are a mixture of pore water and the hydraulic fracturing fluids. An important conclusion is that the chemical and isotopic data for these waters are comparable with data from conventional oil and gas wells from the same basin, at the same general T–P conditions.
This chapter reviews what is known about the geochemistry of water in sedimentary basins in the continental and transitional continental oceanic crust. The emphasis is on water below the zone of shallow meteoric groundwater circulation and on the main processes that are responsible for the modification of the chemical and isotopic composition of these waters including (1) mixing; (2) dissolution of evaporites, especially halite; (3) reflux and incorporation of bitterns, the residual water remaining after the precipitation of evaporites; (4) dissolution and precipitation of minerals other than evaporites; (5) interaction with rocks, principally clays, siltstone, and shale that behave as geologic membranes; (6) activity of bacteria that can survive in sedimentary rocks at temperatures up to ~. 80. °C; (7) interactions with organics, including petroleum and solid organic matter; and (8) diffusion, especially in and near salt domes.
Any crustal fluid can give rise to metasomatism when it migrates from one rock type to another, and metasomatism is normally associated with specific fluid flow paths, such as fractures, faults, shear zones or lithologies which were more permeable than those around them. Examples of representative analyses of a wide range of crustal fluids from the literature are therefore presented and discussed. Except in shallow crustal settings, metasomatism is generally associated with brines, and highly concentrated brines are particularly effective metasomatic agents. Leaving aside mid-ocean-ridge geothermal systems, the most abundant sources of metasomatic fluids are sedimentary basin brines and magmatic fluids, but mantle and metamorphic fluids can also give rise to metasomatism. Basinal brines are initially of two types: low-Br, NaCl brines derived by dissolution of halite, and Br, Ca-rich brines evolved from the bitern brines remaining after halite precipitation. Both types are implicated in ore-formation and metasomatism (e.g. albitisation) in both sedimentary basins and their underlying crystalline basement. Many magmas give off significant amounts of acid fluids, often rather saline, as they crystallise, and these may also contain distinctive volatile components derived from the melt (e.g. B, F) that influence the metasomatic effects, such as greisenisation, that result. The high transition metal contents of magmatic brines mean that they are also potential ore-formers. Some deep-derived magmas act as vectors to bring mantle fluids into the crust. These appear to be brines that are also highly charged with CO2, and one effect of degassing at crustal levels is that these fluids become silica undersaturated, for example they may leach silica during fenitisation. Skarns are a particularly important class of metasomatic rock, and owe their origin in part to the transient generation of secondary porosity as infiltrating silica-saturated aqueous fluids trigger decarbonation reactions in carbonate rocks. They may be formed from metamorphic fluids as well as magmatic ones, but in general metamorphic fluids are not a major cause of metasomatism, except where focussed in subduction, because they are usually released very slowly by endothermic reactions taking place in an over-pressured, and therefore low permeability, environment.
It has long been known that chloride-dominated saline ground waters occur at depth in the UK, not only beneath the sea but also onshore at depths of a few hundred metres. In a few places in northern England, these saline waters discharge naturally at surface in the form of springs. In recent years, however, these saline ground waters have come to be regarded as resources: as potential geothermal fluids intercepted in deep boreholes. Comparisons of the major ions and stable isotopes (δ2H, δ18O and δ34S) of these saline ground waters with North Sea oilfield formation waters, and with brines encountered in former subsea workings of coastal collieries, reveal that they are quite distinct from those found in North Sea oilfields, in that their as δ2H/δ18O signatures are distinctly “meteoric”. δ34S data preclude a significant input from evaporite dissolution – another contrast with many North Sea brines and some colliery waters. Yet, enigmatically, their total dissolved solids contents are far higher than typical meteoric waters. It is tentatively suggested that these paradoxical hydrogeochemical properties might be explained by recharge during Cenozoic uplift episodes, with high concentrations of solutes being derived by a combination of high-temperature rock–water interaction in the radiothermal granites and/or ‘freeze out’ from overlying permafrost that surely formed in this region during cold periods. Geothermometric calculations suggest these saline waters may well be representative of potentially valuable geothermal reservoirs.
La thèse cherche à caractériser les types de fluides à différents niveaux structuraux et types de déformation. Les résultats de la Sierra Bédar indiquent le rôle d'une saumure enrichie en métaux lors des derniers stades de circulation au sein de la croûte ductile dans un domaine encore isolé des fluides de surface. Cette saumure est plus diluée à l'est dans la Sierra Almagrera et où l'impact du système décrochant va devenir de plus en plus important avec du volcanisme et de nombreux gisements. Dans le domaine fragile, des veines de quartz enregistrent des fluides de surface. Suivent des veines de quartz indiquant la réapparition des fluides métamorphiques sous-jacent. La formation de veines de sidérite-pyrite-galène-barytine montre de plus forte salinité et des rapports Cl/Br indiquant la contribution d'une autre source de saumures secondaires issues cette fois des évaporites messiniennes. Le décrochement a modifié le compartimentage de part et d'autre de la transition fragile-ductile
The Bunter Sandstone in the UK sector of the Southern North Sea Basin is a reservoir rock that is typically 200 m or more thick and has variable but commonly fair to good porosity and permeability. East of the Dowsing Fault Zone it is folded into a number of large periclines as a result of post-depositional halokinesis in the underlying Zechstein salt. It is sealed by the overlying Haisborough Group and younger fine-grained strata and is underlain by the Bunter Shale and Zechstein Group. As such it appears to be an attractive target for industrial-scale CO2 storage. However, the very large masses of CO2 that would have to be injected and stored if CCS is to be an effective greenhouse gas mitigation option are likely to cause (a) significant pore fluid pressure rise and (b) displacement of formation brines from the reservoir. A series of reservoir flow simulations of large-scale CO2 injection was carried out to investigate these effects. A simple, 3D geocellular model of the Bunter Sandstone in the NE part of the UK sector of the Southern North Sea was constructed in the TOUGH2 reservoir simulator in which porosity and both horizontal and vertical permeability could be varied. The injection of CO2 at various rates into the model through a variable number of wells for 50 years was simulated and the model was then run forward for up to 3000 years to see how pore fluid pressures, brine displacement and CO2 distribution evolved. The simulations suggest that provided there is good connectivity within the reservoir, and 12 optimally distributed injection locations are used, 15–20 million tonnes of CO2 per year could be stored in the modelled area without the reservoir pore pressure exceeding 75% of the lithostatic pressure anywhere within the model. However, significant fluxes of the native pore fluid (saline brine) to the sea occurred at a point where the Bunter Sandstone crops out at the seabed. This suggests that the potential environmental impacts of brine displacement to the sea floor should be investigated. The injected CO2 fills only up to about 1% of the total pore space within the model. This indicates that pore fluid pressure rise may be a greater constraint on CO2 storage capacity than physical containment within the storage reservoir.
Produced water analyses from the Birch Field, UK North Sea have been interpreted and combined with simulation results to explain the causes of changes in produced water compositions over time. Preliminary conclusions are that two formation waters are present in the oil leg, both trapped at the time of oil emplacement. Lower salinity formation water has been expelled from the Kimmeridge Clay Formation (KCF) and dominates shallower sections of the reservoir. Higher salinity formation water is thought to be ancient Brae aquifer water and dominates the deeper sections. Some lateral variability in formation water compositions is evident. Produced water from individual wells is a mixture of the lower salinity formation water, higher salinity formation water and injected water. Trends in produced water compositions over time reflect a relative decrease in formation water production and increase in injection water production. Depending on the constituent, reactions occurring as a result of injection of water into the reservoir also affect the composition of produced water. The results have challenged previous concepts relating to water production at Birch and will be considered in scale management plans in future. They can also be used to constrain reservoir simulations, to aid enhanced oil recovery decisions and to provide more reliable tracking of injection water and formation waters entering the production wells at Birch.
More generally, this study has demonstrated the importance of evaluating produced water analyses as early as possible after water breakthrough. Integration of reservoir simulation studies with the interpretation of produced water analyses can provide information that benefits scale management, STOIIP calculations, reservoir models, and tracking of injection water as well as providing analogue information that can help reduce uncertainties associated with the development of deep water and marginal subsea fields.
CO 2 is a common gas in geological systems so that planned storage of CO 2 in the subsurface may do no more than mimic nature. Natural CO 2 has a wide number of sources that can be at least partly identified by carbon stable isotope geochemistry. Three pairs of case studies with different reservoir characteristics and CO 2 contents have been examined to assess the natural impact of adding CO 2 to geological systems. Carbonate minerals partially dissolve when CO 2 is added simply because the CO 2 dissolves in water and forms an acidic solution. Therefore, carbonate minerals in the subsurface are not capable of sequestering secondary CO 2 . The addition of CO 2 to a pure quartz sandstone (or a sandstone in which the supply of reactive aluminosilicate minerals has been exhausted by excess natural CO 2 addition) will have no consequences: the CO 2 will simply saturate the water and then build up as a separate gas phase. The addition of CO 2 to carbonate cemented sandstone without reactive aluminosilicate minerals will induce a degree of carbonate mineral dissolution but no solid phase sequestration of the added CO 2 . When CO 2 is naturally added to sandstones it will induce combined aluminosilicate dissolution and carbonate cementation if the aluminosilicate minerals contain calcium or magnesium (or possibly iron). Examination of a CO 2 -filled porous sandstone with abundant reactive aluminosilicate minerals that received a huge CO 2 charge about 8000 to 100 000 years ago reveals minimal evidence of solid phase sequestration of the added CO 2 . This indicates that either dissolution of reactive aluminosilicates or precipitation of carbonate minerals is relatively slow. It is very likely that the slow dissolution of reactive aluminosilicates is the rate-limiting step.
Solid phase sequestration of CO 2 occurs only when reactive aluminosilicates are present in a rock and when the system has had many tens to hundreds of thousands of years to equilibrate. The two critical aspects of the behaviour of CO 2 when injected into the subsurface are (1) that the rock must contain reactive Ca and Mg aluminosilicates and (2) that reaction to produce carbonate minerals is extremely slow on a human timescale. The reactive minerals include anorthite, zeolite, smectite and other Fe- and Mg-clay minerals. Such minerals are absent from clean sandstones and limestones but are present in ‘dirty’ standstones (lithic arenites which are mineralogically immature) and some mudstones.
The analysis of geological analogues shows that injection of CO 2 into carbonate-bearing rocks that do not contain reactive minerals will induce dissolution of the carbonate, whether it is a matrix cement, rock fragment, fault seal or part of a top-sealing mudstone.
In this study, a long-term (up to 1000 years) geochemical modelling of subsurface CO2 storage was carried out on sandstone reservoirs of depleted gas fields in northeast Netherlands. It was found that mineral dissolution/precipitation has only a minor effect on reservoir porosity. In order to validate this, we focused specifically on the reactive surface area of minerals which we measured by Scanning Electron Microscopy. In this way we obtained distributions for the measured reactive surface areas of each individual mineral. Subsequent parameter analysis and Monte Carlo sampling of these distributions revealed that in the Rotliegend sandstones, the surface area of quartz has by far the largest effect on SMCO2 (total amount of CO2 sequestered as mineral). The proportional relation of SMCO2 and quartz reactive surface area leads to the conclusion that CO2 injection in a sandstone reservoir with fine grained quartz has a higher potential for mineral trapping of CO2.
In addition, using parameter analysis we also could determine the effect of surface area of each mineral on its own dissolution/precipitation mechanisms as well as on the other minerals. For example, the results showed that dawsonite precipitation is proportional to kaolinite and K-feldspar surface area.
It is important to understand both the origin and destruction of H2S in petroleum since it is toxic, corrosive andenvironmentally damaging. Sour gas (H2S) in the Central and Northern North Sea elastic-dominated basins is locally present at concentrations ≥ 20,000 ppm. The origin and destruction of H2S has been examined using large basin-scale datasets of water, gas and oil geochemistry and fluid inclusion volatile analysis from a sweet oil field. Both thermochemical sulphate reduction (TSR) and organic-sulphur compound cracking have, probably occurred given the depth distribution patterns of H2S, the sulphate concentration in formation water and the sulphur content of oils. There is evidence that TSR-derived H2S has backreacted with oil so modifying the sulphur isotope ratio of the oil. H2S is precipitated as pyrite in many sandstones and it only accumulates, or is trapped within inclusions, in clean sandstones that have limited available iron.
Input data for water composition are required in order to numerically simulate diagenetic episodes. In rock-dominated, closed-system modelling, the composition of water initially present in the pores has at most only a minor influence on the stability of the system, and is controlled by the mineral composition. In open-system modelling, the composition of infiltrating water can play an important role.Brent water salinities of the Greater Alwyn area exhibit a regional trend from the North to the South. The ratio of these waters varies along two trends: it is higher in the North than in the South. Alkalinity and published pCO2 values are used to calculate pH under subsurface conditions. Very few silica measurements are available. Aluminium analyses of pore water are not available. Some reservoirs of the Greater Alwyn area experienced a major reduction in permeability due to illite and quartz precipitation, coeval with kaolinite and K-feldspar dissolution. Saturation of present-day Brent waters with respect to these minerals is examined.The method proposed in Part 1 is applied to reconstruct a range of possible compositions for ancient waters in Brent reservoirs, between several extreme conditions. One of these extremes is provided by buffering water with a set of minerals chosen from petrographic considerations. The other extremes correspond to reasonable states of over-saturation with respect to particular minerals, e.g. quartz, and concern the values of dissolved Si and Al, which are the least well characterised concentrations from the routine analyses of formation waters.
A long-term study of produced water chemistry from a North Sea field was used to investigate the mechanisms of water mixing and water-rock interaction in the reservoir. Seawater flooding has continued throughout much of the production life. Detailed repeated sampling of the produced water was undertaken and has produced an extensive dataset, yielding information on water chemistry variations in space and time. The dataset documents both fluid mixing in the field and the physical, chemical and thermodynamic response of the system to the injection of seawater. Analysis of the data establishes the nature of the controls on the composition of the scale-prone formation water, and enables an in-depth look at the fluid-rock interactions occurring in the reservoir during a waterflood.
Changes in produced-water chloride concentration through time reflect changing proportions of injected seawater and formation-water, revealing differing patterns of injected-water breakthrough over the field. However, parallel changes in the concentrations of less conservative fluid components provide evidence of fluid-mineral interactions that occurred in the reservoir on the timescale of the waterflood. For example, calcium is enriched in the produced fluid relative to a linear mixture of original formation-water and seawater, while magnesium is depleted, probably reflecting dolomitisation of calcite and growth of clay. Barium and sulphate are strongly depleted due to precipitation of barite. However, mass balance highlights an additional sink for sulphate, possibly reduction to sulphide. Excess silica present in the produced fluid is ascribed to dissolution of silicate phases in the reservoir. Concentrations demonstrate that the produced water is always close to quartz saturation at reservoir temperature, irrespective of the proportion of seawater produced.
Analysis of produced water chemistry provides insights into the inner workings of the reservoir system during a waterflood. Study of individual dissolved species relative to linear mixing lines between injected and formation water allows measurements of the nature and amounts of dissolution and precipitation reactions affecting scaling ions within the reservoir. This allows for greater understanding of the controls on water composition and of the nature of water mixing in the reservoir, leading to improved prediction and planning of scale occurrence, prevention and remediation.
Introduction
Seawater, either untreated or chemically modified, is commonly used for waterflooding offshore oil reservoirs, for pressure support and improved oil recovery. Injecting a fluid into a reservoir with which it is in neither thermal nor chemical equilibrium will have a number of effects. The injected fluid will react both with the water already in the pore spaces of the rock (formation water) and with the minerals in the rock itself. Changes in pressure and temperature will change the thermodynamic stability of the dissolved fluid constituents. As noted by McCartney and others1, the most important effects of seawater injection can be recognised by studying the changing composition of produced water through time.
Situated in the North Sea, Field X has undergone continued monitoring of produced water compositions from all its wells, culminating in a high-quality time-series database. Initial interpretation of the data was for the identification of scaling, but through continued study of all the data we have highlighted evidence of a number of other chemical reactions occurring in the system.
Overall, produced water analyses indicate that mixing between injected and formation water has occurred to different extents throughout the reservoir. In addition, the data show that produced water is significantly depleted in barium, sulphate and magnesium and enriched in calcium and silicon relative to a simple mixture of injected and formation water. This paper aims to summarise the most important points raised in the study of the fluid data and in particular highlights the many potential uses and applications of produced water analyses.
The surveillance of oil and gas production systems for evidence of scale deposition commonly involves trending well inflow performance, pressure, temperature, rate of flow and the composition of produced water. Surveillance using produced water composition data can be improved by the application of geochemical understanding of formation waters, including the processes that controlled the evolution of formation water composition. Also, use of multivariate data analysis (MDA) techniques provides methods that can resolve subtle and significant differences, and increase the reliability of information derived from produced-water composition data. MDA provides a systematic method of evaluating data as a whole as opposed to single variable investigation, which can overlook significant information.
The information derived from geochemical understanding of formation waters and MDA can also benefit reservoir and production management, for example reservoir compartmentalisation studies and subsea production allocation.
Shell Exploration and Production UK Ltd's operations in the North Sea have benefited from a combined application of geochemical understanding of formation waters and MDA. In addition, formation water composition data derived from residual salt analysis (RSA) of reservoir core has provided additional data for several fields, which has assisted produced- water data interpretation and reservoir management. Examples of the benefits include the case of the ETAP Heron Cluster fields, where well-intervention costs in excess of £1 million per well were saved. The Bittern field benefited from postponement of scale-squeeze treatments when erroneous tracer observations suggested injection water breakthrough had occurred. HPHT prospects in the Central Graben have been assessed for the risk of halite deposition before drilling based on regional studies.
The water chemistry prevailing in the BP Amoco operated Miller field presents one of the harshest scaling environments in the North Sea. The high barium, moderate salinity brine, coupled to a relatively high bottom hole temperature produces a scaling environment that dictates the need for high concentrations of exotic scale inhibitor chemistry for downhole scale control. These high levels of inhibitor, typically 10-200 ppm, are particularly difficult to sustain over long production periods. This leads to a relatively short squeeze life and thus high well intervention frequency and deferred oil costs.
Vinyl sulphonate chemistry has been shown to be particularly effective at controlling scale deposition under Miller conditions. However, its retention characteristics are less than ideal, leading to short treatment life. A new chemistry has now been developed which realises the benefits of the vinyl sulphonate functionality whilst achieving significantly higher retention and thus the potential for longer treatment life. This has been achieved by incorporating a novel phosphorus containing species into the polymer matrix.
Laboratory studies suggest that the new inhibitor combines significantly improved performance with superior environmental properties. One field trial has already been completed and another is currently ongoing. The trials have already achieved a significant increase in squeeze life.
Results to-date indicate that operating costs can be significantly reduced through development of a novel chemistry designed to meet the specific needs of a particularly harsh scaling environment.
The continual need to reduce oil production costs has led Mobil North Sea Limited (MNSL) and TR Oil Services Limited (TROS) to develop a new strategy for maximising the efficiency of scale squeeze treatments on the Beryl Field. The strategy combines the advantages of enhanced precipitation scale inhibitors with a squeeze performance enhancer. The development and use of innovative chemical technologies such as these, has provided the industry with an important new route to achieving cost reduction goals.
The enhanced precipitation scale inhibitor in use on Beryl has been reformulated to provide optimum performance over an eight-hour shut-in period. Core flood studies have shown that the lifetime achieved through use of the optimised product is, in fact, longer than that seen with the original scale inhibitor, which utilised an eighteen-hour shut-in period. The ten-hour reduction of the soak time has meant that production down time during squeeze treatments has been dramatically reduced.
The scale squeeze enhancer has been developed in conjunction with BP Chemicals and BP Exploration to promote the retention of scale inhibitor during a squeeze treatment. Experimental work has indicated that application of the squeeze enhancer in conjunction with the reformulated inhibitor package will result in significantly longer squeeze lifetimes than those previously seen on Beryl.
Following the laboratory work, several field trials in the Beryl Field have been performed. The correct deployment of the enhancer with the precipitation squeeze inhibitor has resulted in a significant reduction in the re-treatment interval and well clean up times leading to significant cost savings.
Over the past three years, the Oilfield Scale Research Group at Heriot-Watt has conducted a number field studies to evaluated scale inhibitors for both downhole squeeze application and topside continuous injection for a number of North Sea operating companies. This paper presents an approach for screening commercial sulphate and carbonate scale inhibitors for field application. The screening results, which include data from static/dynamic inhibitor efficiency, static adsorption, compatibility and thermal stability are used to rank the performance of commercial scale inhibitors. From this short list, a small number (1 to 3) candidate products are taken on to reservoir condition coreflooding. In the screening of topside scale inhibitors, no adsorption tests are conducted.
Results from adsorption and precipitation type corefloods will be compared for polymer and phosphonate chemistries selected using these screening procedures. Such corefloods serve both to evaluate the squeeze lifetime performance and to assess the levels of formation damage caused by the scale inhibitor package. The strategy of deriving a dynamic isotherm which can be utilised in computer modelling of the coreflood data to produce a "Field Squeeze Strategy" will be outlined. This systematic approach provides a set of effective and economical methods for the chemical screening of scale inhibitors. This results in an improved field application strategy with longer squeeze lifetimes, while minimising formation damage potential.
Corrosion and corrosion inhibition of carbon steel in various types of crude oils and associated water (formation water) have been studied using electrochemical and weight loss measurements. The corrosion rate of carbon steel depends critically on the types of formation water. The influence of three amino ethyl imidazoline derivatives, aminoethylimidazoline of linolenic acid, aminoethylimidazoline of oleic acid, and aminoethylimidazoline of propionic acid on the corrosion of carbon steel in these aggressive solutions was studied at different concentrations and temperatures. The inhibition efficiency of these inhibitors decreases in the order: aminoethylimidazoline of linolenic acid > aminoethylimidazoline of oleic acid > aminoethylimidazoline of propionic acid. The adsorption of imidazoline derivatives obeys the Langmuir adsorption isotherm. The thermodynamic parameters indicate that imidazoline derivatives inhibitors are physically adsorbed on the carbon steel surface. The influence of oleic imidazoline inhibitor was studied in fluids having different oil/water ratios. The data revealed that the corrosivity of an oil/water fluid generally increases with the increase of water cut.
The formation of CaCO3 mineral scale is a persistent and expensive problem in oil and gas production. The magnesium ion, present in formation and injection waters in downhole conditions, is a key determinant in CaCO3 scale formation. In the work reported herein, the kinetics of calcium carbonate scale formation is studied both in the bulk solution and on a metal surface. The effect of the Mg2+ ion on the scale formed on the metal surface has been studied systematically in this paper including aspects of the kinetics, morphology, and Mg/Ca ratio of the deposit on the metal surface. The Mg2+ ion adsorbs onto the deposited crystals and the ratio of Mg2+ in the deposit formed on the metal surface is proportional to the ratio of Mg/Ca in the scaling water. The distribution coefficient in surface deposition and in bulk solution is a constant and independent of the concentration of Mg2+ ions in the bulk solution. Simultaneously, the Mg2+ ion accelerates the crystal transformation from vaterite to calcite and adsorbs on the surface of vaterite and calcite causing an increase in surface roughness in addition to distortion of crystals.
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