Impairment of flow by way of mineral scale formation is a major complication affecting production in the oil and gas industry. Soured reservoirs contain hydrogen sulfide (H 2 S) that can prompt the formation of exotic metal sulfide scales, leading to detrimental fouling that can negatively impact production. The contrast in the mode of precipitation (solid formation from liquid solution) and deposition of both sulfide scale and conventional inorganic carbonate and sulfate scales is herein examined. Design of an experimental rig allowing diffusion of H 2 S gas into the brine phase of a sealed reaction vessel resulted in a realistic representation of scaling processes occurring within sour reservoirs. Multiphase conditions, induced by introduction of a light oil phase to scaling brine within a turbulent regime, aimed to study the effect of oil and water wetting on pipeline fouling. Performance of a range of antifouling surfaces was determined through measurement of scale deposition by gravimetry and microscopy techniques. Under conditions modeled to reflect a typical H 2 S-containing reservoir, the contrasting scaling mechanisms of conventional calcium carbonate (CaCO 3 ) and barium sulfate (BaSO 4 ) scales when compared to lead sulfide (PbS) scale highlighted the critical role of the light oil phase on deposition. While conventional scales showed deposition by both crystallization and adhesion onto surfaces, the thermodynamic driving force for PbS prompted rapid bulk nucleation, with adhesion acting as the overwhelmingly dominant mechanism for deposition. The results showed that the addition of a 5% v/v light oil phase had a profound effect on scale particle behavior and deposition onto antifouling surfaces of varying wettability as a result of two processes. Primarily, the oil wetting of hydrophobic surfaces acted as a barrier to deposition, and second, adsorption of scale crystals at the oil/water interface of oil droplets within a turbulent oil-in-water emulsion resulted in adhesion to hydrophilic surfaces after impaction. It is therefore proposed that sulfide scale, typically deposited in the upper regions of production tubing, is driven by adhesion after formation of a PbS solid-stabilized Pickering emulsion. This contrasts with the commonly held view that metal sulfides precipitate and deposit similarly to conventional scales, whereby salts crystallize both directly upon surfaces and in the aqueous bulk phase as solubility decreases toward the wellhead.

A complete experimental setup for in situ infrared transmission spectroscopy studies of solid/liquid reactions in Ziegler-Natta catalysts has been developed. The main part of the apparatus, the flow cell, facilitates separate recording of the liquid-phase spectrum and the superimposed solid/liquid spectrum, and thus allows solid and dissolved species during reactions to be distinguished. Addition of solutes and exchange of solution during the experiments are made possible, thus allowing subsequent reactions to be studied. The setup is suited also for liquid reactions, and, in principle, for other chemical systems as well. The construction of the flow cell and the operation conditions are based on pressure-drop calculations of the flow in the apparatus. Two experimental studies are included to demonstrate the use and to document the performance of the setup: (1) the reaction of MgCl2 with dissolved ethyl benzoate and AlEt3 in succession, and (2) the interaction of a MgCl2/ethyI benzoate support during TiCl4 treatment. In the latter, a hitherto unknown TiCl4/EB complex is discovered in the TiCl4 solution.

This paper presents a mechanistic approach to modeling the reservoir souring process in the Ekofisk Field, located in the Norwegian sector of the North Sea with over 6 billion STB OOIP and currently producing about 300,000 BOPD and injecting around 500,000 BWPD sea water. The objectives of this study were to determine if observed increases in H2S concentrations from this seawater-flooded oilfield were due to microbiological activity and, if so, to estimate future H2S production with further seawater injection and proposed produced water reinjection. Mechanisms considered in the model were imbibition and water flow through a highly fractured chalk formation; generation of H2S due to the activity of sulfate-reducing bacteria (SRB); and partitioning of H2S between the oil, water, and gas within the reservoir and in the topside separation system. Model-calculated H2S production rates for individual wells, waterflood patterns, and full-field compared well to actual rates. Results indicated that both the water-oil and gas-oil ratios have a large impact on measured H2S concentrations in the produced gas, but that increased water production is responsible for significant increases in total H2S production. However, results also indicated that only a small fraction of the biogenic H2S will be transported to the producer. This model presents a new approach for evaluating and forecasting the effects of souring for a naturally fractured reservoir whereby a biofilm is developed on the fracture faces and microbial nutrients are provided by incoming seawater and from formation water initially in the chalk matrix. It incorporates a mechanistic understanding of all of the key processes and is calibrated using the actual historical production rates from wells in several waterflood patterns. Presented in this paper are the model-forecasted results for the field-wide H2S production associated with continued seawater injection. Introduction The Ekofisk Field, discovered in 1969, is located in the far southwest corner of the Norwegian Sector of the North Sea.1 The reservoir is an elongated anticline comprised of naturally fractured chalk that produces from two major formations: Ekofisk and Tor. The overlying Ekofisk Formation is 9600 feet deep and varies in thickness from 350 to 500 feet while the Tor Formation varies in thickness from 250 to 500 feet. Porosities for the two formations range between 30 and 48% with a matrix permeability of 1 to 3 mD. The initial reservoir temperature was 131°C. Estimates place OOIP at 6.4 billion STB and GIIP at 10.3 trillion scf with an ultimate waterflood recovery factor of 38%.2 At peak production in 1976 Ekofisk produced over 350,000 STB/D of 38° API gravity oil. A waterflood (375,000 BWPD unheated sea water capacity) was implemented in 1987 in the northern half of the field.3 The success of this waterflood prompted its field-wide expansion over the next several years to a capacity of 830,000 BWPD.Seawater is fine filtered, continuously disinfected with ultraviolet light, deaerated, and batch treated with biocide prior to injection.4 Breakthrough of seawater occurred in several Ekofisk wells as early as 1994.Current production from the PL018 license area that includes the Ekofisk, Eldfisk, Embla, and Tor Fields is approximately 365,000 STB/D and 140,000 BWPD with peak production of water expected to reach about 260,000 BWPD by 2012. The produced water is separated from the oil and gas at five different offshore installations and then cleaned to provide oil-in-water concentrations below 40 ppm before being discharged to the North Sea. The final separation of oil, water, and gas is performed on the centralized J Platform.

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Mineral scale formation and deposition in down-hole completion equipment such as subsurface safety valves can cause dramatic and unacceptable safety risks and associated production losses and operational costs. Current scale removal strategies involve both mechanical and chemical technologies, each of them having their own advantages depending on the type of mineral scale and its location. However, these techniques are often costly and of limited efficiency. The current study assesses the ability of a range of chemically and morphologically modified coatings to prevent/reduce mineral scale surface fouling. Building-up on previous work done under static conditions, this paper presents results from scaling tests under laminar and turbulent dynamic conditions using a rotating cylinder electrode under in a complex (mixed) scaling environment (supersaturated w.r.t. calcium carbonate, barium sulfate, strontium sulfate, barium carbonate and strontium carbonate). The study shows that if properly selected, surface treatments represent a promising approach to reduce scale deposition on downhole equipment surfaces that are critical to maintain equipment functionality and thereby well safety barrier integrity. By analyzing the scaling behaviors observed within the set of surfaces tested, suggestions of the controlling factors in anti-fouling on these systems are presented and discussed.