TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractBefore the development of a field it is worthwhile to determine the characteristics of crude oil emulsions. This may be even more important if the wells are to be equipped with electrical submersible pumps (ESPs) which can create a shearing environment resulting in tight emulsions. One such study was conducted to determine the characteristics of emulsions from a cluster of oil fields planned for development. The proposed development is to produce from three fields and several different reservoirs. The central crude processing facility will process ~500 MBD of crude and 50 MBD of water. A study was conducted to determine the impact of ESP on emulsions and hence on the ESP design (horsepower) and the possibility of demulsifier injection downhole. The emulsion properties are also needed for the design of central wet crude handling facilities. A series of emulsion tests were conducted with crudes from different reservoirs at bottomhole and surface temperatures, range of watercuts and shearing conditions. The results are provided in terms of 'relative' tightness of emulsions from different reservoirs. The viscosities of various emulsions were also determined. The results indicate that demulsifier injection facilities will be needed at the wet crude handling facilities and possibly in wells from one reservoir that has a high asphaltenic and viscous crude. The paper provides a framework of laboratory emulsions studies that can provide valuable information for the design of processing facilities before they are built. The paper also discusses some practical aspects of demulsifier treatment program including demulsifier selection and optimization and methods to prevent emulsion problems.
This paper presents the results of a unique emulsion and sludge problem in one of the largest offshore oil fields in the world. The problem is related to heavy emulsion sludge deposition in the crude handling facilities. Very viscous emulsions containing 70–90% water were encountered in the offshore facilities where they were plugging up over 50% of the effective separator volume. As there is no bottom water drain at these crude handling facilities, the wet crude forms a very tight, complex emulsion that settles down in the equipment. This problem is anticipated to increase in the future as the water production increases in the field. A comprehensive study was initiated to diagnose and remedy the problem. Recommendations were made early on to conduct field trials by injecting a demulsifier at the wet crude handling facilities to control the sludge problem. Field trials were conducted at three offshore facilities. Samples were collected before and during demulsifier injection. A new method recently developed for testing emulsions was used to evaluate the removal of the thick emulsions. These field trials were successful and the emulsion/sludge problem has been brought under control. The sludge has been removed and the crude handling facilities are running with minimal demulsifier injection. This paper will describe the research work including a new method to test emulsions, comprehensive results from field trials, and highlight the teamwork between the Research Center and field personnel in successfully solving and controlling an operational problem. Introduction Saudi Aramco has encountered operational problems due to emulsions in several fields that have led, at times, to an increase in demulsifier usage, production of off-spec crude, and occasionally caused equipment upsets in the wet crude handling facilities (WCHF) and gas oil separation plant (GOSP). The problem is usually at its worst during the winter, due to lower temperatures. This paper describes a unique emulsion problem in a large, Saudi Arabian offshore oil field. This field produces Arab Medium crude oil (API 25) that is processed in four GOSPs offshore. The main producing reservoirs are sandstone. A schematic of the GOSP is shown in Figure 1 and consists of two high pressure production traps (HPPT) and two de-sanders. The traps and de-sanders operate at 250 psi and 80–90°F. The gas is separated and is transported to shore through a gas line and the crude oil is pumped to an onshore WCHF through undersea trunklines. The problem is related to heavy emulsion sludge deposition in the de-sanders. This is one of the consequences of the processing of wet crude in the field. Prior to 1997, the production from the field was dry oil and all the wet wells were shut-in. However, during the last four years, several wet wells have been put on-line. The opening of the wet wells has created an emulsion problem at the offshore GOSPs and the wet crude forms a very tight, complex emulsion that settles down in the de-sanders. The tight emulsion (viscosity in excess of several thousand cP at 80–90°F) plugs the de-sanders that have to be flushed periodically. This adversely affects plant operations. This problem is anticipated to increase in the future as the water production increases in the field. To tackle the sludge problem an Emulsion Team was established with members from the R&D Center, Operations and Production Engineering. Based on laboratory studies at the R&D Center, field trials were conducted at the offshore GOSPs with a recommended demulsifier. These are described in the paper.
Before the development of a field, it is worthwhile to determine the characteristics of crude-oil emulsions. This may be even more important if the wells are to be equipped with electricalsubmersible pumps (ESPs) which can create a shearing environment resulting in tight emulsions. One such study was conducted to determine the characteristics of emulsions from a cluster of oil fields planned for development. The proposed development is to produce from three fields and several different reservoirs. The central processing facility (CPF) will process ≈500,000 B/D oil and 50,000 B/D of water. Previous studies determine the impact of ESP on emulsions and on the ESP design (horsepower) and the possibility of demulsifier injection downhole. The emulsion properties are also necessary for the design of central wet crude handling facilities. A series of emulsion tests was conducted with crudes from different reservoirs at bottomhole and surface temperatures, range of water cuts, and shearing conditions. The results are provided in terms of "relative" tightness of emulsions from different reservoirs. The viscosities of various emulsions were also determined. The results indicate that demulsifier injection facilities will be needed at the wet crude handling facilities and possibly in wells from one reservoir that has a high asphaltenic and viscous crude. This paper provides a framework of laboratory emulsions studies that can provide valuable information for the design of CPFs before they are built. This paper also discusses some practical aspects of demulsifier treatment programs, including demulsifier selection and optimization and methods to prevent emulsion problems.
Due to operational constraints natural gas liquids (NGL) are sometimes blended with stabilized crude. This option is considered when there is a temporary surplus of NGL and for better NGL management. The NGL blend ratios are generally very small and conservative and are not meant to impact the crude quality. The blends have to meet rigorous vapor pressure specifications. A systematic study was conducted to determine the vapor pressures of different NGL/crude oil blends. The evaluation considered various factors that impact the vapor pressure of the blends, including the NGL/crude oil ratios, degree of crude stabilization, temperature, and the retention time in the pipeline and/or in the crude tanks. An important aspect of the study was to determine the "foaming tendency" and volume changes during blending. Vapor pressure curves were determined for different blends of stabilized crude with NGL as a function of temperature. The data included both the true vapor pressure and Reid vapor pressure of the blends. The experimental data were supplemented with equation of state simulations. Low vapor pressure data of blends are scarce, and the paper discusses the physical properties of NGL/crude oil blends. Introduction The gas plants occasionally reject NGL into stabilized crude streams to effectively manage the produced NGLs. This could be due to excess NGL inventories, process limitations or a temporary lack of customers for NGL. A small amount of NGL can be rejected into the stabilized crude streams instead of flaring it. A simplified schematic of the possible NGL rejections into various crude streams is shown in Fig. 1. The main rejections include C3+, C4 and C5 products into the Arab Light (AL) crude oil. At present, the rejection limits are based on empirical data and past experiences. Such limitations may be resulting in product and revenue losses. Considerable revenues gains can be achieved if the rejection rates can be safely maximized without impacting the crude quality. The availability of maximum safe rejection limits at various plants will also provide better NGL management and flexibility in operations. This paper provides the results of a comprehensive study that was conducted to provide the maximum safe rejection limits of various NGL into stabilized crude streams. The crudes included Arab Light (AL), Arab Extra Light (AXL) and Arab Medium (AM). The NGLs included C3+ NGL, C4 and C5 products, and pure NG. The results take into consideration all factors that impact NGL rejection into the crude, including crude stabilization depth, temperatures, and the retention time in the pipeline and/or in the crude tanks. The paper also provides comprehensive vapor pressure data of different NGL+crude blends, the "foaming tendency" and volume changes of the blends. The procedures described in this paper provide a framework for low-pressure PVT experimentation and can be used for determining the vapor pressures of crudes and low volatility hydrocarbon products. Experimental Details The systems and variables investigated in this study included:Crude Oils: Stabilized AL, AXL and AM crudes.NGLs: C3+ NGL, C4 and C5 products, Pure NG.Temperatures: 60–150°F.Blending Ratios: up to 5% (vol) rejection.Stabilization Depths: Shallow and Deep. The crude oil samples were collected from the crude stabilization plants, and the NGLs were collected from different gas plants. The samples were collected in pressurized cylinders and were not allowed to get contaminated with air. The fluid compositions of the samples were analyzed by gas chromatography, and the results are presented in Table 1 (crude oils) and Table 2 (NGLs). Three types of experiments were conducted with the samples and their blends:Low pressure vapor-liquid equilibrium (VLE) data including the true vapor pressure (TVP) and Reid Vapor Pressure (RVP).Blend densities for selected blends.Foaming tendency of the crude during NGL rejection.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractBefore the development of a field it is worthwhile to determine the characteristics of crude oil emulsions. This may be even more important if the wells are to be equipped with electrical submersible pumps (ESPs) which can create a shearing environment resulting in tight emulsions. One such study was conducted to determine the characteristics of emulsions from a cluster of oil fields planned for development. The proposed development is to produce from three fields and several different reservoirs. The central crude processing facility will process ~500 MBD of crude and 50 MBD of water. A study was conducted to determine the impact of ESP on emulsions and hence on the ESP design (horsepower) and the possibility of demulsifier injection downhole. The emulsion properties are also needed for the design of central wet crude handling facilities. A series of emulsion tests were conducted with crudes from different reservoirs at bottomhole and surface temperatures, range of watercuts and shearing conditions. The results are provided in terms of 'relative' tightness of emulsions from different reservoirs. The viscosities of various emulsions were also determined. The results indicate that demulsifier injection facilities will be needed at the wet crude handling facilities and possibly in wells from one reservoir that has a high asphaltenic and viscous crude. The paper provides a framework of laboratory emulsions studies that can provide valuable information for the design of processing facilities before they are built. The paper also discusses some practical aspects of demulsifier treatment program including demulsifier selection and optimization and methods to prevent emulsion problems.
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