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Abstract In the shadow of low oil prices, it is necessary to develop economically and environmentally friendly solutions. In oil and gas industry, majority of the production stream is water. This water is produced with the hydrocarbon to surface. This requires the separation of the fluids produced and then treating those streams to abide with environmental regulations and clients' specifications. CDOWS (Centrifugal Downhole Oil Water Separator) technology is believed to provide high separation quality, high oil recovery with reduction of operating costs and less surface facilities. The development process involves simulation of tubular centrifuge using a computational fluid dynamics (CFD) software to analyze the parameters affecting separation. After that, an experimental set up is erected which mimics in-well CDOWS. The novel design of the tool involves specially designed weir to collect the oil and water through concentric tube configuration. The parameters tested through simulation include; flow rate, RPM, tubing length, tubing diameter, API and oil/water ratios. The experimental set-up is used to confirm the sepration in the rotating tube as it is made of acrylic material. The CFD model involves a rotating cylinder (tubing) in which oil and water are introduced from the inlet. The feed of oil and water exhibits high centrifugal forces resulting in their separation through and to the outlet of the tubing. The experimental design mimics the actual in-well design which can be implemented in a well. The design can be configured easily to change the tubing parameters. After conducting the studies, a sensitivity analysis using design of experiment approach (DOE) and response surface plots is produced to emphasize on parameters and their interaction effects. Findings include better separation using higher RPM, ID, L, water salinity, API. The most influential factor is RPM which can be controlled and thus will define costs for later stages of the project. This paper presents the first work on CDOWS which is analogous to in-well configuration aiming for a solution with reduced costs.
- Research Report > Experimental Study (0.64)
- Research Report > New Finding (0.50)
Abstract Efficient processing of fluids from flowing wells is an important function on a topside facility to maintain optimum hydrocarbon production. Many oil and gas facilities face the additional challenge of limited available footprints to process additional capacity. Normally, onshore facilities move process fluids from the wellhead to a de-sander unit, and then to a 2-phase or 3-phase separator unit. In offshore and onshore production facilities, fluids from multiple wells are sometimes co-mingled in a manifold and processed through two or three separation stages with progressively lower pressures to separate gas, crude oil, and produced water. Sequential pressure letdown and numerous fluid pump-around loops to separator vessels and interconnected piping with pumps, valves, and instrumentation occupy a large space on a wellsite. To add processing flexibility in an ever-changing fluid composition (water cut, gas vapor fraction (GVF), and solids loading) from co-mingled production wells and to remove the bottleneck at the topside processing capacity, a chemically enhanced, smart compact separation system has been developed. The new separation system is based on the centrifugal (CF) separation principle. After comprehensive laboratory testing and Computational Fluid Dynamics (CFD) model validation for separated fluid streams, the system was tested in field conditions at an unconventional wellsite to benchmark mechanical reliability, separation effectiveness, and robustness. The modular design concept of this new system enables operation at 200 to 10,000 bbl/d fluid capacity at nominal increments by adding units in parallel. The system is designed to handle 30 to 99% water cut and normally encountered solids or fines concentrations. This technology is also able to handle ever-changing fluid conditions at the well such as production decline or water cut changes by using a digital interface that controls the separator operation based on inlet fluid conditions. This smart, compact separation system enables efficient separation and reduces the need for over-sized separation vessels. A 2,000 bbl/d, two-phase (oil/water) system has consistently achieved residual oil-in-water (OIW) levels below 400 ppm in the water outlet without chemical addition enhancement. The residence time for separation is less than a minute for the 2,000 bbl/d prototype unit, enabling it to be used as an alternative to a freewater knockout (FWKO) vessel. The prototype unit has a 4-in. diameter housing that is mounted on an 8-feet cast-iron frame with a 15-hp electrical motor coupled as the prime mover. The lab and long-term field test results have also indicated that the CFD simulations can effectively reveal the mechanism of oil-water separation as well as validation of separator sizing parameters for various flow capacities. The refined control algorithms are still in development phase, but when completed they will control the separator dynamically as flow conditions change in the well. A field trial to test chemical demulsifying agents will determine the final separation efficiency of this system.
- North America > United States (0.47)
- Asia (0.46)
Abstract Oak Ridge National Laboratory (ORNL) is currently developing a Centrifugal Downhole Separator (CDHS) which will extend the application of remotely operated separations equipment developed for the nuclear industry to in-well recovery of oil with in-situ recycle of the produced water. These units have been successfully used for surface treatment of produced water and wastewater generated during environmental clean-up operations. Performance data have shown that centrifugal units are capable of separating stable emulsions into "single-phase" streams with generally less than 1% cross-phase contamination. Initial testing will be conducted with a bench-scale separator to determine the separation efficiency of various crude oils and to provide information necessary to scale up the separator. Information from the bench-scale unit will be used in the design of a larger prototype, which will have a much larger height/diameter ratio and will incorporate some of the components necessary for downhole operations. The prototype separator will be operated in the lab to verify scale-up parameters and separation efficiencies, as well as to provide information necessary to design a full-scale system. The full-scale system will be fabricated, installed in the field, and operated to demonstrate the technology. This paper discusses the testing to date of the bench-scale separator with a crude oil having an API gravity of 34.06°. INTRODUCTION Produced water is the largest generated waste stream by volume in the Gulf Coast region and is typically a mixture of formation and injection process water that contains oil, salts, chemicals, solids, and trace metals. In 1991, Louisiana generated over 1 billion barrels and Texas generated 7.5 billion barrels of produced water as a result of oil and gas operations. More than 250 million barrels of produced water are discharged each year to surface waters in both Texas and Louisiana (1). Because of the tremendous volume of water generated and the specific constituents typically present, discharge of produced water from oil and gas production operations has been increasingly scrutinized in recent years for potential impacts on sensitive habitats. The discharge of produced water to the environment is regulated by the Environmental Protection Agency (EPA) in the United States. The maximum concentration of contaminants in produced water that can be discharged will be limited by the latest EPA regulations under the Clean Water Act. These rules are expected to reduce current discharges of toxic pollutants (including arsenic, cadmium, and lead) by more than 200,000 lb/year, conventional pollutants (such as oil, grease, and solids) by 2,800,000 lb/year, and nonconventional pollutants (such as chlorides, ammonia, and aluminum) by about 1,500,000,000 lb/year. Future regulations are likely to be more restrictive and may include zero-discharge standards (2,3). As a result of these regulations, the industry has limited options for disposal of produced water. Traditional treatment and disposal of produced water primarily have been direct discharge to surface waters or subsurface formations. Zero discharge will dramatically increase the operating costs for produced water disposal in the Gulf Coast region and significantly limit the economic life of producing wells and fields. The American Petroleum Institute (1) estimated in March 1995 that the initial cost for compliance with zero-discharge guidelines would be $0.3 billion for coastal areas and over $3.2 billion for offshore areas.
- North America > United States > Texas (0.54)
- North America > United States > Louisiana (0.44)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Water is very often associated to the oil production, for geological reasons, but also because it is the most frequent mean of secondary recovery. However all fields are not comparable in their behaviour. In the best cases water is effectively contributing to the oil sweeping and the bulk of the oil reserves can be produced at low water cuts. In other cases, it can be said that water is inevitable to the oil and huge volumes of high water liquids must be lifted from an early stage to produce the oil. In some cases, mechanical or chemical water shut off techniques can help to reduce the water production however, depending on the specific conditions, they are not always cost effective, their implementation can be tricky, and their efficiency may be limited in time. Therefore the operator is often left with the standard solution of upgrading its field and process facilities to cope with the produced water constraints. However, due to the increase difficulties resulting from the drastic new environmental regulations, the operators tend to focus more than before on the produced water associated cost. A typical offshore field production history and capex and opex breakdown was analysed to highlight the impact of the water on a field economy. The new interest linked to the emerging technology of downhole separation and re-injection has motivated the testing of a DOWS unit on the well LA-90 in the Lacq Superieur field in France and results of this operation are presented. Considering the shortcomings in the existing static cyclone technology which is implemented in the down hole separation systems, TFE has undertaken since three years a R&D program based on an innovative concept of rotary cyclone. The base of the theory and its implementation are presented along with the promising preliminary results. Introduction In many places, water is inevitable for the oil. Although initial oil production from a field is often dry, the water often invites itself in the well at some stage, sometimes much earlier than initialy anticipated. Some reservoirs are connected to large aquifers providing a strong pressure support to the oil production. Depending on the geology of the structure and on the reservoir characteristics, different schemes can account for the water production process. In the bottom drive reservoirs, where the water is directly underlaying the oil, the water coning, resulting from the pressure drawdown applied to the formation, is governing the water production. In this type of configuration, the critical rate per well is generally too low to be economical. In fact, there are little reservoirs where an efficient gravity drainage can be implemented. For the edge drive reservoirs, production wells are drilled much far away from the oil and water contact, but water tends to channel faster through high permeability drains and reaches the producers sometimes very early in the life of the field. When the oil layer is only connected to a small aquifer, there is not a sufficient pressure support to compensate for the oil production. Then the reservoir pressure is decreasing with time, which is often very detrimental to the ultimate oil recovery. Hence, a pressure maintenance scheme is required and water (or gaz) has to be injected into the reservoir to balance the oil offtake. Depending again on the reservoir characteristics and on the geology, the water injection wells can be located at the periphery of the oil layer, away from the producers, or on the contrary they must be drilled between the oil wells. Obviously, the same comments as before, concerning the risk of early water production, can apply to these schemes. In all cases, an early water breaktrough results in a reduce sweeping efficiency which has a negative impact on the oil recovery. This is even aggravated by the unfavourable mobility ratio between the oil and the water, since the viscosity is generally higher for the oil than for the water. Therefore, a longer production period is required in order to make up for the delayed oil and huge cumulative volumes of water are produced ultimately.
- Europe > France > Nouvelle-Aquitaine (0.34)
- Europe > United Kingdom > North Sea (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Europe > France > Nouvelle-Aquitaine > Lacq Basin > Lacq Superieur Field (0.99)
- Europe > France > Nouvelle-Aquitaine > Lacq Basin > Lacq Field (0.99)
- Europe > France > Meillon Rousse Field (0.99)
Abstract Cyclonic devices are ubiquitous in industrial processes and have been used for particle separation for decades. However, designing a highly efficient, compact cyclone for erratic flow conditions and particles of varying types, sizes and density remains a challenge. This paper aims to present the challenges, lessons learnt and recent development in cyclone technology for solid separation. Primarily, a discussion on typical cyclonic desander geometries is conducted. Failures and sub-optimal operation of cyclonic wellhead desanders within the company are analysed, and subsequently the failure mechanisms and factors leading to inefficiencies are identified. Computational Fluid Dynamics (CFD) simulations and flow loop testing are further performed to verify the particle separation efficiency and quantify the erosion risks of the typical cyclone geometries. The typical cyclonic geometries are considerably less efficient in multiphase-flows compared to the gas-solid or liquid-solid flows. As a result, the overflow section of the cyclone often contains particles larger than the design specification. Changing operating envelope over time, for example, reducing production and changing flow regime affects cyclone efficiency over time. Based on a systematic analysis of the desander failures in the fields, a few design improvements have been proposed to overcome these limitations, resulting in a novel technology. This new cyclonic technology with multiple barrier system can successfully maintain the 98% target removal of 10microns particle under erratic multiphase-flows conditions. Furthermore, it can be designed to handle various types of particles e.g., sands, HgS and other solids. The versatility of this system provides promising technology for ageing fields with excessive solids production.