This study aims to investigate the impact of in situ reactions on scaling risk due to various injection water types in a giant offshore carbonate reservoir in Abu Dhabi. The goal is to understand how different water compositions, temperatures, and injection strategies affect the formation of calcium sulfate (CaSO4) and strontium sulfate (SrSO4) scales, and to provide recommendations for managing and mitigating these scaling risks to reduce operational costs. The study employs reactive transport modelling tools (CMG GEM) to simulate the impact of various factors such as injection water composition, temperature, rates, and the location of injection wells relative to production wells. The model also considers features like the oil-water contact and gas-oil contact. The output includes ion concentration profiles, water composition profiles, and water production rates at production wells impacted by seawater breakthrough. These profiles help identify the evolution of scaling risks in the production wells. The GEM model predicts no SrSO4 scaling risk for any of the producers, but there is a CaSO4 scaling risk for all three producers that cut seawater. The high temperature of the formation (104°C) plays a critical role in reducing sulfate scaling risk due to the natural precipitation of CaSO4 deep within the reservoir. The study concludes that the reservoir itself acts as a natural desulfation plant, depleting the brines of scaling ions and thereby protecting the wells. The findings suggest that installing a Sulfate Reduction Plant (SRP) is not necessary. Matrix transport has been considered in this study. The effect of the presence of fractures acting as a "short circuits" high conductivity pathways is discussed in the paper. The novelty of this study lies in its use of reactive transport modelling to account for in situ geochemical reactions, providing a more accurate assessment of scaling risks. The study's findings challenge the conventional need for SRPs by demonstrating that the reservoir itself can act as a natural desulfation plant. This approach not only reduces operational costs but also offers new insights into scale management strategies for similar fields.

Summary The drive towards net zero by 2050 has led to the development of alternative energy sources, with a focus on geothermal energy projects. Geothermal brines often contain dissolved minerals and gases that cause scale deposition in wells and plant equipment, leading to decreased efficiency in thermal energy production and reduced flow capacity in injection wells. Geothermal plant conditions and brine chemistry of each geothermal plant vary greatly, making the selection of a suitable scale management process crucial for sustainable energy production. Prevention through chemical inhibition or removal is preferred over costly mechanical methods, though nonchemical alternatives are attractive for reducing the CO2 footprint. Chemical treatment options include continuous topside injection, scale squeeze, or batch treatment in injection/production wells. High temperatures and water throughput in geothermal wells challenge chemical scale control and removal. Selected inhibitors/dissolvers must be thermally stable up to 250°C, preferably biodegradable, and effective against calcium carbonate and silica/silicate scales. Geothermal brines contain dissolved CO2 and H2S, making fluids corrosive. Therefore, the interaction between scale and corrosion inhibitors must be considered in any management strategy, possibly requiring modified laboratory test methods, especially for plants with water reinjection. This paper will review geothermal scale and its mechanisms of formation and management options, including chemical and nonchemical treatments. It also discusses the impact of well completion, high water production, corrosion, CO2 footprint, and the challenges of chemical treatments regarding thermal stability and laboratory testing.

Mutual solvents (MS) have been extensively applied prior to the main scale inhibitor (SI) treatment slug of squeeze treatments. Evidence from the field indicates that MS pre-flushes are beneficial, however, no systematic evaluation of their role has been performed. A series of core floods have been undertaken to elucidate the predominant mechanism that leads to these beneficial effects. Factors investigated included; presence/absence of an oil phase, type of oil phase present (mineral/crude oil), and core wettability (oil/water-wet). The objective was to investigate the impact of a specific mutual solvent (EGMBE) on the retention of DETPMP in cores that had been pre-flushed with MS prior to the main treatment and compare them to the corresponding core flood where no MS pre-flush had been applied ("No MS" case). In all the core floods, scale inhibitor injection and return profiles were evaluated and compared. Saturation changes throughout each flood were also monitored. In all the water-wet cases, the return profiles for the flood with MS as a pre-flush were seen to be comparable to the "No MS" case; the mutual solvent showed no obvious improvement in SI adsorption and its return in the long post flush tail. However, it was found that applying a MS pre-flush to an oil-wet core significantly enhanced squeeze lifetime in comparison to its "No MS" counterpart. The mutual solvent phase behaviour was also consistent with that for the water-wet cases, with it breaking through earlier than expected due to the presence of a residual mutual solvent phase that is stripped from the core throughout the injection stage. A repeat experiment using the same materials did not show the expected improvement in SI return, however, examination of the crude oil used, indicated that it had changed significantly from the first experiments such that comparison to the initial "No MS" case was invalid – a different wetting state was achieved. It is still our belief that the predominant mechanism by which MS beneficially enhances Squeeze lifetimes is through a wetting change from oil-wet to a more water-wet state, however further work is required to confirm this hypothesis.

Abstract The first stage of a squeeze treatment entails a pre-flush, usually containing a mutual solvent that prepares the surface of the rock and allows greater retention of scale inhibitor that is injected during the main part of the treatment. We use experimental studies to tackle the issue of mutual solvent propagation and its impact on oil displacement and inhibitor retention. Clashach cores were used in this study, and the propagation of mutual solvent and subsequent scale inhibitors through the core were studied, along with any influences on rock properties such as permeability and on residual phase saturations. It was evident that during waterflooding a high residual oil saturation affects squeeze lifetime, and that mutual solvent can partially compensate for this, although the effect could not be definitively identified. Thus, further corefloods were conducted to understand how long it takes to remove residual mutual solvent from the core plug during the main treatment injection stage, and what is the influence of mutual solvent concentration in the pre-flush on this process. The corefloods conducted were thus: i. Three floods with different concentrations (100%, 75% and 50%) of mutual solvent, using the injection of tracers at various stages, to identify how the residual phase saturation changes with main treatment aqueous phase volume throughput, and ii. Three scale inhibitor floods at residual oil saturation (using Multipar H). One with no mutual solvent pre-flush and two with a mutual solvent pre-flush (100% EGMBE). The difference between the latter two mutual solvent pre-flush floods was the amount of residual oil in the core prior to mutual solvent injection. The results are discussed in detail, to understand the effect of the mutual solvent during a squeeze treatment under typical field conditions. According to the results it is proposed that using mutual solvent as a pre-flush enhances scale inhibitor squeeze lifetime, by increasing scale inhibitor adsorption/retention, due to a wettability change towards more water-wet – as evidenced by the reduction in residual oil saturation. Furthermore, more pore volumes of aqueous phase main treatment (up to seven) were required to displace the residual phase when lower mutual solvent concentrations were used in the coreflood pre-flush stage. The results of this work indicate that mutual solvent concentration, and the ratio of main treatment volume to pre-flush volume should be carefully considered when designing squeeze treatments, since the contact between the aqueous scale inhibitor solution and the rock will be affected by the ability of the mutual solvent to displace oil, and by the volume of main treatment required to displace the mutual solvent rich pre-flush. Finally, modelling work was undertaken using the isotherms generated from the corefloods to demonstrate the impact on squeeze life of various mutual solvent applications.

Abstract Electromagnetic devices (EMDs) have been reported to be a method for scale management in the field. One proposed mechanism for scale mitigation is that the device imparts an electromagnetic (EM) pulse that provides sufficient energy to the fluids to cause homogeneous nucleation, resulting in the formation of very small particles (5 to 9 µm), which will pass through the production system, hence preventing/reducing heterogeneous nucleation and deposition on the tubing surface. Previous work revealed that such a device had a measurable impact on a Barium Sulphate scaling system. This paper extends this work by performing visualisation experiments and comparing the results with baseline findings previously published in 2016 using the same test apparatus. Comparative experiments were performed with the device "on" and "off" and images of crystal growth within the test cell taken at regular intervals over the test period. The same conditions as those from 2016 (scaling brines (SR), T, P and Q) were used and then extended by increasing the residence time of the fluid in the test cell by a factor of 2 and 4. The images were analysed using MATLAB to quantify the number of crystals formed, their size and the surface coverage achieved. ESEM images of the test coupon within the cell were also taken for analysis. From all the comparative experiments performed, it was seen that the EMD had a significant, measurable, and positive effect on BaSO4 control with a reduction in crystal growth rate, crystal size and the numbers formed. Comparison with previous data were consistent with results obtained with a lower SR scaling system, suggesting that the EM signal has effectively reduced the surface saturation ratio of the system as it passes through the test cell. Increasing the residence time of the fluid within the EM field enhances the impact of the device in terms of the number of crystals formed, their size and surface coverage within the cell. All these observations support the previously proposed mechanism, that the EMD promotes bulk (homogeneous) nucleation and precipitation, and therefore reduces the energetic favourability of surface (heterogenous) crystal formation.

Abstract The injection of sea water for the pressure support of oil fields is commonly associated with the biogeneration of hydrogen sulfide (H2S) by sulfate reducing bacteria and/or archaea (SRB/SRA). H2S is extremely toxic and corrosive, as well as providing a source of sulfide ions for the formation of iron, zinc and/or lead sulfide scale. However, H2S production is rarely, if ever, associated with seawater breakthrough and its retardation can be linked to a number of mechanisms. Certain minerals (e.g. siderite, FeCO3, and/or iron oxides, FexOy) may react with produced H2S and retard its progress towards the producer wells. This is a generally beneficial effect but it is difficult to quantify and it is generally estimated from direct matching to the field appearance of H2S. Alternatively, H2S retardation factors are based on correlations with the mineralogy of the field and these are rather unreliable, since few experimental results have been published. In essence, this quantity (the H2S retardation factor) is more of a "matching parameter" rather than being truly predictive. Candidate mechanisms for sulfide scavenging by iron-bearing minerals have been experimentally identified and scavenging capacities have been determined for siderite FeCO3 in modified static adsorption tests and in dynamic pack floods, for aqueous-only systems. The effects of changing several conditions were studied, including temperature, initial pH and grain size. A combination of dissolution/precipitation and surface displacement mechanisms were identified in the static bottle tests and further confirmed during the dynamic sand/siderite and crushed-core pack floods. ESEM-EDX and particle size analyses established the presence of mobile FeS (<100 µm) in the column after the flood had reached completion, confirming the bulk precipitation of FeS from dissolved Fe2+. Bringing together these two mechanisms allowed for the rationalisation of the observed scavenging profile, with reference to the Ksp of siderite. By further understanding the mechanisms of H2S scavenging experimentally, it will be possible to incorporate these into field-prediction models. The absolute values obtained for the 8 wt% siderite packs were 1.03 and 1.74 mg/g at 25 and 96°C, respectively. Crushed core packs yielded significantly higher values of 5.76 and 5.80 mg/g at 25 and 96°C, respectively, which have been hypothetically attributed to the presence of iron-bearing clays in the core samples.

Summary The development of effective scale-inhibitor (SI) squeeze treatments remains a challenge for carbonate reservoirs because of their substantial chemical reactivity with the SI. This in turn might potentially lead to uncontrolled SI precipitation and induced formation damage. This work takes a systematic approach to understanding the retention mechanisms of SI in carbonate formations with respect to the detailed carbonate-formation mineralogy, type of SI, and reservoir conditions in the absence of oil. Static adsorption/compatibility experiments, described previously as apparent adsorption tests (Kahrwad 2008), were performed to evaluate the areas of different retention mechanisms [pure adsorption (Γ) and coupled adsorption/precipitation (Γ/Π)] of different SI species in brine. Experiments were conducted for five SIs at various conditions: initial pH values, mineralogical compositions (calcite, limestone, and dolomite), and temperatures. The SI species used in this study included a phosphonate [di-ethylene tetra-amine penta (DETPMP)], a phosphate ester [polyhydric alcohol phosphate ester (PAPE)], and three polymeric SIs [polyphosphino carboxylic acid (PPCA), P-functionalized copolymer (PFC), and sulfonated polyacrylic acid copolymer (VS-Co)]. All precipitates were studied using environmental scanning electron microscopy/energy dispersive X-ray (ESEM/EDX) and particle-size analysis (PSA). The overall results from these coupled Γ/Π experiments are as follows: For the polymeric SIs (PPCA, PFC, and VS-Co), the highest retention levels were observed at low pH for all carbonate substrates, because of the increase in divalent cations calcium and magnesium (Ca2+ and Mg2+, respectively) available from rock dissolution for SI–M2+ ions (divalent cations) precipitation. For DETPMP and PAPE SIs, the retention level was greatest at higher pH values, because the SI functional groups were more dissociated and, hence, available for complexation with M2+ ions. The polymeric VS-Co predominantly showed pure adsorption with only a low amount of precipitation (Γapp ≈ 1.2 mg/g) in contact with the dolomite substrate. This is because of the presence of sulfonate groups (low pKa). For polymeric inhibitors, the retention level (Γapp) was highest on calcite (highest relative calcium content), followed by limestone and dolomite. DETPMP and PAPE SIs showed the highest retention levels on dolomite (higher final solution pH and more SI dissociated), followed by limestone and calcite. For all SI species, higher retention (more precipitation, Π) was observed at elevated temperatures. At lower temperatures, an extended region of pure adsorption was observed for all SIs. The information presented in this study will be helpful in SI product selection on the basis of mineralogy and reservoir conditions. As a consequence, longer squeeze lifetimes and improved efficiency of SI deployment in carbonate reservoirs can be achieved. In addition, this study provides valuable data for validating models of the SI/carbonate/Ca/Mg system that can be incorporated into squeeze design simulations.

Summary CO₂ injection for Carbon Capture and Storage (CCS), particularly in carbonate formations, will disturb the chemical equilibrium between the rock and formation fluids, causing reactions to occur. The use of a reliable geochemical model of the system will help to understand the overall geochemical interactions and the risk and opportunities that these interactions will introduce for safe and secure storage. In this work, reactive transport modeling was conducted to investigate the dissolution rates of carbonate minerals upon injection of bicarbonate (HCO₃) saturated brine at temperatures between 21°C and 90°C. The injection of the HCO₃ saturated brine is performed to mimic the condition of the reservoir in the long-term where the system is re-equilibrating after the injection of CO₂. The reaction rate calculation was performed by adopting two different reaction rate models (1) Transition-State-Theory (TST) and (2) Arrhenius rate models. The predictions were calibrated with measured dissolution rates obtained from a set of core flood experiments conducted on outcrop and field samples. This work suggests that the TST model cannot accurately predict the reaction rate, particularly in the saturation regime close to equilibrium. The Arrhenius rate model was found to be better in predicting the dissolution rate under those conditions.

Abstract Electromagnetic Devices (EMDs) have been used for scale management in the field. The proposed mechanism for their function is that the device imparts an electromagnetic pulse that provides sufficient energy to cause homogeneous nucleation, resulting in the formation of very small particles (5-8 microns) which pass through the production system, preventing heterogeneous nucleation and deposition. This paper summarises an experimental programme to examine the proposed mechanism of operation of the EMD under controlled laboratory conditions. Flow experiments were performed under ambient conditions using a mixed North Sea Seawater (NSSW) / Nelson Forties Formation Water (NFFW) scaling system. Experiments were performed with the EMD active and compared to baseline experiments where the EMD was inactive, to assess if the device impacted the scaling process. A full quantitative assessment for each experiment was performed including; assessment of the mass of scale deposited and its location, full effluent analysis by Inductively Coupled Plasma Optical Emission Spectroscopy (ICP) and effluent sample filtration for solids content, morphology using Environmental Scanning Electron Microscopy / Energy Dispersive X-ray (ESEM/EDX) analysis and particle size distribution (PSD). From the experiments performed, it was found that the device impacted the scale deposition process in comparison to when it was not activated. Results indicated that although a similar amount of scale is lost from solution, less deposit was collected in the test apparatus itself. The precipitate in the effluent samples (which had passed through the apparatus) was found to have a mean particle size in the region of 10 microns, with a significant proportion of the distribution of particles below 1 micron; this was confirmed by ESEM/EDX and PSD. A further particle distribution range was identified as less than 0.22 microns. This material (10-20% of that injected) passed through the 0.22 micron filter used to collect the solid, but was accounted for when the experimental procedure was adapted. The results from this study indicate that under the conditions used, the EMD has an impact on the scaling process resulting in homogeneous nucleation of smaller scale particles that are transported through the apparatus. This supports the mechanism reported previously and provides a greater understanding to how such devices work in the field.

Summary The bulk “apparent-adsorption” behavior (Γapp vs. Cf) of two polymeric scale inhibitors (SIs), polyphosphino carboxylic acid (PPCA) and phosphorus-functionalized copolymer (PFC), onto carbonate mineral substrates has been studied for initial solution pH values of 2, 4, and 6. The two carbonate minerals used, calcite and dolomite, are much more chemically reactive than sandstone minerals (such as quartz, feldspars, and clays), which have already been studied extensively. In nearly all cases, precipitates formed at higher SI concentrations were caused by the formation of sparingly soluble SI/calcium (Ca) complexes. A systematic study has been performed on the SI/Ca precipitates formed by applying both environmental scanning electron microscopy energy-dispersive X-ray (ESEM-EDX) analysis and particle-size analysis (PSA), and this identifies the morphology and the approximate composition of the precipitates. For PPCA, at all initial solution pH values, regions of pure adsorption (Γ) (PPCA < 100 ppm) and coupled adsorption/precipitation (Γ/Π) are clearly observed for both calcite and dolomite. PFC at pH values of 4 and 6 also showed very similar behavior, with a region of pure adsorption (Γ) for PFC < 500 ppm and a region of coupled adsorption/precipitation (Γ/Π) above this level. However, the PFC/calcite case at pH = 2 showed only pure adsorption, whereas the PFC/dolomite case at pH = 2 again showed coupled adsorption/precipitation at higher PFC concentrations. For the SIs on both carbonate substrates, precipitation is the more dominant mechanism for SI retention than adsorption above a minimum concentration of approximately 100 to 500 ppm SI. The actual amount of precipitate formed varies from case to case, depending on the specific SI, the substrate (calcite/dolomite), and the initial pH (pH = 2, 4, and 6). Although the qualitative behaviors of both PPCA and PFC were similar on both carbonate substrates, the apparent adsorption of PPCA was higher on calcite than on dolomite, and the apparent adsorption of PFC was higher on dolomite than on calcite. We discuss here how these observations are related to the reactivity of the different carbonate minerals, the resulting final pH (which affects the dissociation of the SI), the Ca-SI binding, and the solubility of the resulting complex.

Reservoirs that produce oil and gas containing no H2S ("sweet" systems) frequently turn "sour" (i.e. produce H2S) after some period of seawater (SW) injection. Certain minerals e.g. siderite (FeCO3), iron oxides (FexOy), and iron-bearing clays may react with produced H2S and retard its progress towards the producer wells. Despite the impact that these parameters may have on the development of reservoir souring models, there are no published experimental studies that have sought to explain the mechanisms of H2S scavenging or to quantify scavenging capacities for commonly occurring iron minerals. Focussing primarily on siderite but with additional data from field core samples, a combination of static bottle tests and dynamic sand pack experiments were used to identify and quantify H2S scavenging. This study has observed two proposed mechanisms for H2S reservoir scavenging, namely dissolution/precipitation, which depends on the stability of the Fe-bearing minerals, and surface displacement, which depends on the relative solubilities of the resultant precipitates. These mechanisms were rationalised using a suite of analytical techniques; ICP-OES, ESEM-EDX, pH data and particle size analysis. Capacities in the order of 0.5 to 13 mg/g (mg H2S per gram of active substrate) were calculated over a range of initial pH values and temperatures.

Summary Unlike other types of inorganic scales, carbonate and sulfide scales are directly correlated to the in-situ concentration of acid gases such as carbon dioxide (CO2) and hydrogen sulfide (H2S), which influence the local pH and availability of reactive species. The common approach to sulfide- and carbonate-scale prediction often does not account for three-phase CO2 and H2S partitioning at different temperatures and pressures throughout the system. This leads to the use of inaccurate compositions and pH values for the mineral-scaling calculations. In this paper, we apply a rigorous work flow (step-by-step procedure) derived from a compositional pressure/volume/temperature (PVT) model to calculate molecular CO2 and H2S distribution, three-phase relative volume changes, compositional changes, and scale-precipitation trends from the reservoir to the wellhead-separation stage using commonly available surface field data, a full PVT software package, and scale-prediction software of the user's choice. A simplified version of the work flow was previously applied to high-CO2 and -H2S gas/condensate wells with production of condensed water only (Verri et al. 2017b). This paper focuses on the field application of our “Rigorous General Work Flow” (Verri et al. 2017a) to North Sea oil wells with high water-cut and medium H2S levels (approximately 2,200 ppmv in the separator-gas phase) to provide sulfide- and carbonate-scale-prediction profiles from reservoir to separator. The combination of reservoir-, production-, and chemical-engineering models using specific iterative processes (within the work flow) has provided a new and rigorous step-by-step procedure for the prediction of combined sulfide and carbonate scales in oil and gas wells, which can be implemented by anyone using any PVT and scale-prediction software.

Abstract The bulk "apparent adsorption" behavior (Γapp, vs. Cf) of 2 polymeric scale inhibitors (SI), PPCA and PFC, onto carbonate mineral substrates has been studied for initial solution pH values of pH 2, 4 and 6. The 2 carbonate minerals used, calcite and dolomite, are much more chemically reactive than sandstone minerals (e.g. quartz, feldspars, clays etc.) which have already been studied extensively. In nearly all cases, precipitates formed at higher SI concentrations were due to the formation of sparingly soluble SI/Ca complexes. A systematic study has been carried out on the SI/Ca precipitates formed, by applying both ESEM/EDX and particle size analysis (PSA), and this identifies the morphology and the approximate composition of the precipitates. For PPCA, at all initial solution pH values, regions of pure adsorption (Γ) ([PPCA] <100ppm) and coupled adsorption/ precipitation (Γ/Π) are clearly observed for both calcite and dolomite. PFC at pH = 4 and 6 also showed very similar behavior with a region of pure adsorption (Γ) for [PFC] < 500ppm and a region of coupled adsorption/precipitation (Γ/Π) above this level. However, the PFC/calcite case at pH 2 showed only pure adsorption, while the PFC/dolomite case at pH 2 again showed coupled adsorption/ precipitation at higher PFC concentrations. For both SIs on both carbonate substrates, precipitation is the more dominant mechanism for SI retention than adsorption above a minimum concentration of ~100 – 500 ppm SI. The actual amount of precipitate formed varies from case to case, depending on the specific SI, substrate (calcite/dolomite) and initial pH (pH 2, 4 and 6). Although the qualitative behavior of both PPCA and PFC was similar on both carbonate substrates, the apparent adsorption of PPCA was higher on calcite than on dolomite; PFC apparent adsorption was higher on dolomite than on calcite. It is discussed in the paper how these observations are related to the reactivity of the different carbonate minerals, the resulting final pH (which affects the dissociation of the SI), Ca-SI binding and the solubility of the resulting complex.

Abstract Unlike other types of inorganic scales, carbonate and sulphide scales are directly correlated to the in-situ concentration of acid gases such as CO2 and H2S, which influence the local pH and availability of reactive species. The common approach to sulphide and carbonate scale prediction often does not account for three phase CO2 and H2S partitioning at different temperatures and pressures along the system. This leads to the use of inaccurate compositions and pH values for the mineral scaling calculations. In this paper, we apply a rigorous workflow (step-by-step procedure) based on a compositional PVT model to calculate molecular CO2 and H2S distribution, three phase relative volume changes, compositional changes and scale precipitation trends from the reservoir to the wellhead separation stage using commonly available surface field data, a full PVT software and a scale prediction software of user's choice. A simplified version of the workflow was previously applied to high CO2 and H2S gas/condensate wells with production of condensed water only (Verri et al., 2016). This paper focuses on the field application of our general workflow to North Sea oil wells with high water cut and medium H2S levels (≈2200 ppmv in the separator gas phase). By following this rigorous procedure and applying the concept of Maximum Dissolved Iron (MDI) we were able to provide accurate sulphide and carbonate scale prediction profiles from reservoir to separator. The combination of reservoir, production and chemical engineering models using specific iterative processes (within the workflow) has provided a new and reliable step-by-step procedure for the prediction of combined sulphide and carbonate scales in oil and gas wells which can be implemented by anyone using any PVT and scale prediction software. However, in our ongoing work, we are building a model which incorporates all of this workflow by coupling together PVT/VLE models with our aqueous scale prediction software.

Summary Work was undertaken to systematically investigate the factors that affect the formation of zinc sulfide (ZnS) in an aqueous system. Experiments were performed at a series of temperatures from room temperature up to 90°C, at a range of initial pH values and in two brine systems. The effect of pH was examined further by changing the salt from Na2S·9H2O to NaSH·xH2O, therefore changing the initial sulfide source from S2– to HS–, as part of an ongoing method-development strategy. The formation of ZnS was achieved by the equivolume mixing of two preheated bottles, which contained aqueous “H2S” and zinc ions, respectively. Having pH adjusted the zinc brine to values calculated by an in-house thermodynamic model, the brines were preheated to the required temperature and mixed. Aliquots were removed at 2, 4, and 24 hours to perform elemental analysis by inductively coupled plasma optical emission spectrometry (ICP-OES), and pH measurements were performed on all samples after they had returned to room temperature. In addition, particle-size analysis and environmental scanning electron microscopy (ESEM) examination of the resulting precipitate were also performed for a subset of the samples prepared. The reaction between zinc ions and aqueous “H2S” was quantitative at all temperatures up to 90°C and in both brines. The final pH values of the supernatant were independent of the zinc brine pH, and instead were dependent on the molar ratio of zinc and sulfide ions. With a high pH, sulfide-dominated, and a low pH, zinc-dominated, plateau regions were seen with a sharp inflection between the two. As a consequence, reaching field-representative pH values was seen to be extremely difficult while retaining the ability to alter the relative concentrations of the reacting ions. Altering the sulfide source yielded the same trend, although with different absolute values. These observations have been rationalized with reference to the thermodynamic constants governing the reaction through scale-prediction modeling. The work presented here provides a greater understanding of the factors governing the formation of ZnS scale and the considerations required for more industrially relevant formation and inhibition experiments in the future.

Summary Combined sulfide/carbonate-scale formation in wells producing from reservoirs with high carbon dioxide (CO2) and high hydrogen sulfide (H2S) represents a serious threat to production efficiency and system integrity. Understanding of both the main source of iron that forms the iron sulfide (FeS) scale and the phase partitioning and effect of the acid gases (CO2 and H2S) is important in devising and implementing the correct sulfide-scale-control program. In this paper, a pressure/volume/temperature (PVT) software package was used to take production data and model water condensation/evaporation and calculate gas compositional changes and CO2/H2S partitioning between the liquid phases. This enabled reservoir-fluid compositions to be predicted by use of an in-house scale-prediction software, with particular focus on the stable concentration of iron in the aqueous phase. A sensitivity study was then performed to assess the parameters that impact iron solubility within the reservoir. With the reservoir-fluid compositions established, changes along the production stream (over a given range of temperatures and pressures) were determined and used to predict scale formation at those conditions. A modeling workflow was developed and tested against field data for the prediction of sulfide/carbonate-scale deposition in gas wells producing from carbonate reservoirs. The workflow was then applied to a number of gas wells in the Middle East that produce 2 to 4% CO2 and 2 to 6% H2S. By understanding changes in flow rate, gas partitioning, and fluid composition along the production stream, it was possible to map the potential scale deposition through the system and to compare these results with scale deposits observed in the field. It was calculated that the pH in the wellbore is low and mainly determined by the partial pressure of CO2, while the pH in the reservoir is higher because of the presence of calcium carbonate (CaCO3). Therefore, it was possible to determine that dissolved iron is highly unlikely to be present in the formation fluids, thus leading to the conclusion that the source of iron from which FeS deposition occurs must be the result of sour corrosion. In addition, the resulting likely profiles of FeS deposition were predicted.

Abstract Scale Inhibitor (SI) squeeze treatments are commonly used to inhibit mineral scaling in reservoirs, hence preventing formation damage and other production problems. Conventional squeeze treatments comprise of five stages, namely: pre-flush, main treatment, post-flush, shut-in and back-production stages. In the pre-flush stage, a mutual solvent (MS) is often applied to the formation either neat or in a blend of water and/or other additives. This practice is believed to offer numerous benefits including: the prevention of emulsion formation, water-blocking avoidance and enhancements to SI adsorption through oil and water displacement. In applying a MS, any additional solid deposits formed due to this pre-flush stage are generally undesirable. The nature of these possible additional deposits and their potential to cause formation damage have not been studied systematically to date. This paper aims to characterise the predominantly inorganic scales formed in mixtures of oil, brine and a mutual solvent. This characterisation is very useful in developing an understanding of the possible risks associated with mutual solvent applications and it will ultimately enable us to the design of better optimised scale inhibitor squeeze treatments including MS pre-flush stages. For a range of mutual solvents, qualitative "pseudo" ternary phase diagrams were produced at room temperature and pressure; it is denoted "pseudo" ternary since the "components" are the MS, a mineral oil and a brine (all of which are actually multicomponent in nature). Two brine chemistries were investigated including a sulphate-free formation brine and normal seawater. These investigations aided the definition of inorganic precipitation regions on the phase diagram as a function of brine chemistry. For the two brine chemistries investigated, the precipitates were collected and analysed using two methods. The first method used ESEM-XRD analysis to produce an elemental composition of the precipitates. This enabled the determination of the abundant elements in the precipitates and the compounds forming these. In the second method, the precipitates were redissolved in de-ionised water, and ICP-OES analysis was performed to determine the relative elemental ratios. Using these two approaches, a decisive characterisation of the predominant precipitates and their proportions can be made. Significant mutual solvent driven precipitation was found to occur at almost all mutual solvent concentrations in seawater, whereas mineral precipitation occurred only at near-neat mutual solvent concentrations in formation brine. This indicates that the sulphate ion may be important. Indeed, in seawater, the precipitates were found to be predominately Na2SO4 and CaSO4 in approximately a 2:1 mix, respectively, with traces of other SO42- and Cl– precipitates. In formation brine, the precipitates comprised almost entirely of NaCl with small traces of other Cl– salts. These findings provide practical means for preventing mutual solvent driven precipitation that can be tailored to specific squeeze treatment designs. In this regard, key considerations would be the use of sulphate-free brines in preparing the pre-flush, and the avoidance of mutual solvent and brine mixtures at near-neat mutual solvent concentrations.

Abstract In fields where it is unattractive to control barite scaling through chemical intervention (e.g. scale inhibitor squeeze treatments), one option is to substitute the injection of seawater with low-sulphate seawater (LSSW) for pressure maintenance. Injecting LSSW minimises the operational risk of barite deposition on injection water breakthrough. The specification for the LSSW sulphate ion concentration dictates the design of the Sulphate Removal Plant (SRP) required and may influence the field development strategy. There is the possibility that barite deposition can occur within gravel packs designed to minimise sand production. It is in these that the potential for scaling was investigated. Dynamic scaling runs were performed in laboratory scale gravel packs using a mixture of a Formation Water (FW) and LSSW. The initial design involved varying the total flow rates and mixing ratio of the brines in order to produce a 'safe envelope' (Ba2+/SO42- composition) that could be used in the field. The experimental procedure was developed to examine the steady-state effluent profiles and to use these to derive the rate constant, k, for barite deposition. This could then be used in a computer model to predict scaling quantities and timescales. Under 'true' LSSW conditions (20ppm sulphate) the steady-state effluent results proved difficult to interpret due to the limits of accuracy. The sulphate levels were then varied in order to increase the level of accuracy, with the hypothesis that, for a given set of conditions (temperature and pressure), the rate "constant" should remain the same for any Saturation Ratio (SR). Upon closer inspection of the derived rate constants, it was discovered that they were not constant but were directly proportional to the SR for the different input concentrations. Plotting the rate constants against SR showed a linear relationship between the two variables. This was confirmed by using sulphate and barium levels that were unrelated to the previous series of tests. The experimental procedure and the resulting model being developed from the work reported in this paper will assist in designing operational procedures to minimise rate related scaling in gravel packs in fields where squeezing is undesirable.

Abstract Scale formation presents a flow assurance challenge to the oil and gas industry. Scale inhibitor squeeze treatments are the most common method used to prevent scale deposition in subsurface applications. Software tools exist which are routinely used to assist with the challenges posed by scale. An important step in using predictive simulation models is validation. Validation requires the collection of field or laboratory data for comparison with the model predictions. The cost and value of various data required for designing scale inhibitor squeeze treatments with SQUEEZE VI has been assessed. The first stage of designing a scale inhibitor squeeze treatment is chemical selection. Corefloods are used to derive an inhibitor-rock interaction function called an isotherm. The possible consequence of terminating a coreflood too early has been demonstrated. An opportunity for reducing the man-hours required to derive an isotherm has been identified. The water production and injection profile in a well is valuable information which, when incorporated into a squeeze treatment model, improves the accuracy of the model's prediction. Possible methods for obtaining this data have been reviewed. The consequences of modelling a squeeze treatment with the wrong flow profile have been demonstrated. After executing a squeeze treatment brine samples are collected and scale inhibitor concentrations are measured. This data is used to determine when the treatment should be repeated and to history match the squeeze treatment model. The cost per barrel of treated fluid may be reduced by collecting samples less frequently. The impact and risk of reducing the sampling frequency on the ability to predict a treatment's lifetime is demonstrated. Lastly, the possible outcomes of reducing the sampling frequency on the ability to effectively history match a model are demonstrated.

The idea of injecting low salinity water into a petroleum reservoir is not novel and was often used in the 70s prior to the injection of surfactant. Recently it was shown that simply injecting sufficiently low salinity water improves oil recovery. Many possible mechanisms concerning low-salinity waterflood have been proposed in the literature. This paper describes an experimental investigation into some of the factors controlling the increased oil recovery observed when low salinity brine is injected into oil saturated reservoir core samples. Extensive chemical analyses were performed on the effluent showing the extent of interaction between the injected brine, the oil and the rock matrix.