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Produced water typically enters the water-treatment system from either a two or three phase separator, a free water knockout, a gun barrel, a heater treater, or other primary separation unit process. It probably includes small amounts of free or dissolved hydrocarbons and solids that must be removed before the water can be re-used, injected or discharged. The level of removal (particularly for hydrocarbons) and disposal options are typically specified by state, province, or national regulations. This article discusses techniques for the removal of free and dissolved hydrocarbons. See Removing solids from water for information on solids removal. Produced water contains small concentrations (100 to 2000 mg/L) of dispersed hydrocarbons in the form of oil droplets. In applying these concepts, one must keep in mind the dispersion of large oil droplets to smaller ones and the coalescence of small droplets into larger ones, which takes place if energy is added to the system. The amount of energy added per unit time and the way in which it is added will determine whether dispersion or coalescence will take place. Stokes' law, shown in Eq. 1, is valid for the buoyant rise velocity of an oil droplet in a water-continuous phase. Several immediate conclusions can be drawn from this equation.
Produced or fresh water being treated may have suspended solids, such as formation sand, rust from piping and vessels, and scale particles, or dissolved solids (various chemical ions). For most uses or disposal methods, these solids may need to be removed. It may be necessary to remove these solids to prevent wear in high-velocity areas, prevent solids from filling up vessels and piping and interfering with instruments, and comply with discharge restrictions on oil-coated solids. This page discusses appropriate removal technologies and handling of the removed material. Solid particles, because of their heavier density (compared to water) and net negative buoyant force, will settle to the bottom with a terminal velocity that can be derived from Stokes' law, as shown in Eq. 1. This equation applies strictly to creeping flow regimes in which the Reynolds number is less than unity; this is mainly concerned with spheres of very small diameter surrounded by a liquid. For very small particles, the inertial forces are much less than the viscous forces because of the low particle mass, and the particle does not enter into a turbulent settling regime. Most sedimentation basins are rectangular flumes with length-to-width ratios of 4:1 or greater to limit crossflow.
Abstract Deepwater platforms in the Gulf of Mexico and elsewhere are transitioning from dry oil or low water cut production to higher water cut production. These platforms face unique challenges resulting from water and crude incompatibilities, high salinity, no advance characterization of the water treatment issues, and a lack of space for water treatment equipment. The lessons learned by deepwater operators can provide an experience base upon which future operators can draw to assist them with projects to debottleneck and/or improve produced water treatment on their deepwater platforms and FPSOs. Equipment and practices which have worked well and not worked well for treating produced water on floating platforms are described and the issues pertinent to the deepwater operation of this equipment are identified. The impact of the deepwater operating environment on produced water treatment systems is discussed. Platform motion, high shear across control valves or pumps, production from multiple reservoirs, process recycle streams, and the use of hydrate inhibitors or other chemicals all impact the design of a water treatment process and the operation of water treating equipment. The experiences detailed in this paper are intended to help engineers avoid the process design and equipment selection issues which were problematic for earlier deepwater operations.
Abstract It has often been noted that water treating systems in the North Sea differ from those in the deepwater Gulf of Mexico (GoM). The objective of this paper is to provide an understanding of the reasons for these differences. In terms of platform technologies, and extraction strategies, there are fundamental differences between the two regions. FPSOs (Floating Production Storage Offloading) and fixed leg platforms are commonly used in the North Sea, whereas in the deepwater Gulf of Mexico there are currently no FPSOs, and only one fixed leg platform (Bullwinkle). Floating Spars and Tension Leg Platforms are typically used in the deepwater Gulf of Mexico. Thus, there is much greater deck space and weight availability for North Sea platforms than in the deepwater Gulf of Mexico. In addition, almost all North Sea fields are developed using pressure maintenance which relies on water and/or gas injection. Hence the water production in many of these fields has reached high water cut. In the Gulf of Mexico, there is only a handful of fields with water injection and most production is relatively dry. The approach in this paper is to compare the systems to Best Practices in water treating system design and to consider the reasons for deviation from the Best Practices. Factors which account for this deviation include capital and operating costs, extraction techniques, reservoir characteristics, the properties of the fluids being treated, the target specifications, and the obvious differences in platform type (fixed structure in shallow water versus floating structure in deep water). In addition, modeling tools are used to answer "what if’ questions. This provides a detailed understanding of the relative importance of various factors which differentiate the systems in the two regions (such as inlet fluid shear and temperature, separator flux rate, residence time, application of hydrocyclones, etc). While the overall conclusions of the analyses can be readily anticipated (i.e. deepwater systems are designed to minimize weight and space), the detailed understanding provided here gives insight into the design of water treating systems in general. It emphasizes the importance of carrying out effective water treating early in the process (i.e. in primary separation as done in the North Sea), and the necessity of using large end-of-pipe equipment when this is not possible (as in the deepwater, due to high cost of weight and space).
Abstract Water is one of the cheapest and the most abundant injection fluid for oil extraction. Hence, as the hydrocarbon production increases, the amount of water injected escalates which brings the necessity of the proper management and treatment of produced water. The produced water quality can vary greatly depending on water injection processes employed. Thus, we aim to develop a thorough understanding of the expected quality of produced water originating from different thermal enhanced oil recovery (EOR) processes to manage oilfield waters. In this study, produced water from steam flooding (SF), steam assisted gravity drainage (SAGD), solvent-SAGD (S-SAGD), hot water injection (HWI), and in-situ combustion (ISC) processes were characterized. The anions and cations were analyzed by an ion chromatography. Total dissolved solids (TDS), conductivity, pH, total organic content, and average particle sizes of colloids were measured. The stability of colloids was determined by Zeta potential. All analyses were performed on the produced water samples collected at different three stages of the processes; at the initial, intermediate, and final stage of each process. As expected, conductivity strongly correlated with the concentration of the ions present in produced water samples. Sulfate and total organic carbon (TOC) concentrations showed a linear relation. During steam and hot water based injection processes, which were conducted with quartz and kaolinite mixtures, clay-water interaction was found significant, and this interaction increases with injected fluid temperature. Based on zeta potential measurements, the produced water from steam based EOR processes exhibited higher stability than ISC. In other words, the colloids in produced water originated from ISC was more prompt to settlement which makes produced water from ISC good candidate for chemical coagulation. The steam based processes indicated lower TDS value in produced water than ISC, however, when the produced volumes were considered, ISC had advantages due to significantly low volumes of produced waters. Our results indicate that the proper selection of the bitumen extraction method impacts the bitumen-water interaction and produced water management becomes feasible.