New system handles UBD surface fluids offshore
DRILLING / COMPLETION TECHNOLOGYNew system handles UBD surface fluids offshoreA high-specification, surface separation system, designed and built for underbalanced drilling offshore, satisfies weight and space limitations while remaining fully automatedColin Munro and Paul Radcliffe, Deutag UBD Services, Aberdeen
The desire to create a generic surface separation package (SSP) designed specifically for offshore UBD projects led to a successful collaboration between Deutag and Merpro Process Technologies. The initial goal was not to produce a highly optimized design based on one set of operating criteria, but to create one that is robust, flexible and able to operate successfully in a full range of drilling environments. Additionally, the design had to be suitable for installation on both mobile drilling units and permanent offshore platforms. While robustness, flexibility and modularity were deemed more important than a highly efficient, narrowly optimized system, all design aspects were based on results of extensive modeling, and sound, thorough engineering. System components are described in detail within this article. Design Parameters The SSP is designed to carry out the four specific activities during UBD operations. These include:
To achieve these aims, the system must be able to treat a wide range of fluids and flowrates produced during underbalanced drilling operations. The system has been designed to meet the following throughputs:
Process Description The SSP design utilizes a three-stage separation process, Fig. 1. The first stage is a slug catcher (V-101) that removes free gas and bulk solids from incoming well fluids. A knock-out vessel (V-103) is included to remove any liquid in this gas stream prior to discharge to the flare. The second stage uses solid / liquid hydrocyclones (V-104) to remove fine solids exiting from the first stage. The third stage (V-102) treats the solids / free fluid stream exiting the first stage, to effect separation and stabilization of the condensate.
Gas Separation The SSP is designed to complete two-stage degassing and be within offshore crane lifting limitations. Based on the range of inlet pressures and flowrates anticipated, skidded weights of various possible designs were calculated. For the single-stage option, this was found to be in excess of typical offshore crane limits and therefore untenable. Two stages of gas separation were selected to provide a flexible process plant that could be split into a number of skids, all below the maximum allowable skid weight of 20 t. First-stage gas handling (V-101). The first-stage separator must remove bulk gas from inlet well fluids when UBD operations are underway. Thus, this vessel has been sized to handle slug flow conditions. These high gas flowrates are accompanied by an increase in the fluid arrival pressure. The pressure in the first-stage vessel will rise due to this increased annulus pressure, as well as an increase in back pressure from the flare piping. So, it is not a valid assumption to design the first-stage separator, based on maximum gas flowrate and minimum arrival pressure. In low-pressure and / or high flowrate conditions, some liquid carryover is expected in the gas line. For this reason, gas discharging from the first-stage separator is passed through a separate condensate knock-out pot (V-103). There, any liquid present in the gas is removed and returned to the process, upstream of the second-stage separator (V-102). Inclusion of this knockout pot also allows for greater flexibility in equipment layout and selection, as well as reducing the height of the first-stage separator. Second-stage gas handling (V-102). Free gas is removed in the first-stage separator, so any gas handled in the second-stage separator will be the result of evolution from the process liquid, due to the pressure drop between vessels. Separated gas is demisted prior to flaring or routing to the production train. Efficient condensate separation. To ensure efficient separation in the second-stage separator, condensate is degassed at the lowest possible pressure prior to storage. This reduces excess flashing of condensate in the storage tanks and reduces the inert gas blanket pressure required in them. Care also has been taken to ensure that solids carryover is minimized, because fine particles can stabilize water and condensate emulsion. In addition, residence time within the second-stage vessel has been calculated, to optimize effective separation of condensate and drilling mud. Controlling Foam Three strategies — cyclonic inlets, chemical injection and spray bars — have been incorporated into the surface facilities’ design, to combat foam production in the first and second-stage separators. Foaming problems are more likely in the first-stage vessel, where gas flow rates are higher. In addition, devices for foam control have been incorporated in the second-stage vessel as a precaution. More specifically, cyclonic inlets have been installed in the separators, to provide rapid gas and liquid disengagement while using enhanced gravity to collapse foam before it becomes a problem. The chemical injection points are included upstream of both the first and second-stage separators, to allow anti-foaming agents to be introduced, as required. Anti-foam spray bars allow the injection of fluid into the separator above the foam level. Injection of the fluid, which may be diesel, drilling fluid, seawater or any other compatible liquid, is used to collapse any foam that does form. Liquid Separation The first-stage separator handles slug flow conditions. To simplify this operation, the first-stage separator functions as a simple degasser and solids removal vessel, with no provision made at this stage for liquid / liquid separation. The second-stage vessel separates condensate from the drilling fluid, after bulk degassing and solids removal take place in the first-stage separator. Liquid separation is optimized by inclusion of a chemical injection point upstream of the vessel. Condensate containing less than 10% BS&W is pumped to storage. Drilling fluid is pumped into slurry lines prior to discharge into rig shakers. Solids / Drill Cuttings Separation Detailed calculations to predict solids settling were carried out. They established where solids will drop out from the process stream and assessed the amounts of solids that are likely to carry over with the condensate, into the storage system. Solids are separated from process fluids in two locations — the first-stage separator (V-101) where coarse material is removed and vessel (V-104) where fine solid particles are discharged. In both locations, patented TORE technology is incorporated at the vessel base, in place of more conventional slurry pump solutions for solids removal. This allows higher slurry concentrations, reduces power and eliminates pump problems at elevated operating temperatures found offshore. The TORE is a hydraulic or pneumatic conveyor with no moving parts, Fig. 2. It consists of a concentric feed section that has a central discharge tube, where a motive fluid (such as drilling fluid) is used to displace process material.
Drilling fluid enters a swirl chamber via a tangential entry, to generate spinning motion. It passes through a conical section that preserves angular momentum to the annular cylinder. Fluid then leaves the conveyor and mixes with solids in the process vessel. A phenomenon known as a precessing vortex core (PVC) occurs beneath the foot of the central tube and is responsible for excellent fluidization of solids, leading to their subsequent transportation. A PVC is an unstable, time-dependent, three-dimensional vortex core that precesses around the geometrical center. Its occurrence results from shear between the driving vortex (swirling flow exiting the conveyor into the vessel) and the forced vortex (swirling flow entering the conveyor via the inner tube). Using conveyor sizes between 10 mm and 75 mm, trials have been carried out at the University of Cardiff, the Council for Scientific and Industrial Research (South Africa), Merpro Process Technologies and Merpro Manufacturing Services. Several parameters determine performance, typically measured by slurry density, pressure drop and power required. Design variables include size of solid particles to be transported; conveyor type; conveyor orientation in the vessel; and, its relative dimensions. Operating variables include flowrate, pressure and type of driving fluid. The advantages are elimination of particulates in pumps with less shear forces; automatic solids removal, with no risk to operators or the environment; ability for process control; a small space-time requirement compared to other similar systems; and easy installation (with limited structural support), operation and maintenance. Overall, capital and operating costs (power, for example) are low. Flow Measurement Liquid and solids flowrates are measured at three locations. Initially, slurry exiting the first separation stage is monitored by using a Coriolis meter that gives information on flowrate, relative density and percentage of solids. Second, slurry discharging from the second separation stage is measured in isolation, also using a Coriolis meter. Finally, drilling mud flow from the second-stage separator is measured via turbine flow meters. All three measurements are combined, to give an overall cuttings and drilling fluid flowrate. Providing individual measurements allows process control to be optimized. It also supplies real-time data on solids distribution for reservoir analysis. Short holding time for solids in the system and continuous solids removal allow real-time solids samples to be collected at the shale shakers. This eliminates the need for a high-pressure sampling device. Erosion Issues Surface processing of produced and drilling fluids requires that an emphasis be placed on material selection, optimization of line sizes, minimization of velocities and systematic monitoring techniques to reduce the impact of erosion. Loss of pipe wall thickness, due to erosion, is monitored continuously upstream and downstream of the choke, to ensure that integrity of the piping is not impaired. In addition, a strict system of continuous wall thickness checks is employed while the system operates. Line size was optimized during front-end engineering and design to minimize erosion, solids blockage, cost and weight. Equipment Layout A modular design allows greater flexibility of the package, Fig. 3. In turn, with a minimum amount of modification, the SSP can function in a wide range of drilling environments and process fluid from oil and / or gas fields. This modular approach and emphasis on piping arrangements allows individual components to be plugged in or removed as required, to suit specific UBD operations
In the complete package, equipment is split into several separate skidded modules, one control cabin and associated interconnected piping. Further developments include an option to remotely position the control center inside the accommodation module. Integration Of Ubd Functions A state-of-the-art data acquisition system, with PLC controls for various separator and rotating control head operations, is included in the SSP. This system is tied to all necessary equipment for collection of drilling parameters. The collected data is displayed in real-time form, trend plots and stage totals. Collected data also is used to control various control valves, as well as trigger audio-visual alarms. Advanced data acquisition and control enable UBD supervisors to actively control separator and rotating control head operations from the control cabin and rig floor. The high level of automation and integration, plus incorporation of state-of-the-art data acquisition and process control, will lead inevitably to a reduction in manning levels typically found in current operations. In addition to the offshore SSP, a simple system for inclusion on land-based drilling rigs also has been developed. This system can be operated by rig crews in reduced hydrostatic conditions and incorporated as a permanent addition to rig inventory. Addition of this system provides the potential for increased ROP and brings about a reduction in loss-related drilling problems, such as differential sticking. This system also can operate in fully underbalanced situations by inclusion of additional modules and provision of fully experienced, UBD supervisory personnel. Acknowledgment
 The authorsColin Munro is a UBD specialist at Deutag UK Ltd., in Aberdeen, Scotland. His 18 years of experience include working onshore and offshore in the North Sea, West Africa and Southeast Asia. In addition to extensive supervisory and operational experience, Mr. Munro also is well versed in HSE issues, and has been involved in a wide range of specialized UBD studies and industry initiatives. Involved in underbalanced drilling since 1996, his experience includes equipment selection, feasibility studies, planning issues and creation of operational documentation. Mr. Munro is a graduate of Aberdeen University. Paul Radcliffe is a broad-based well engineer with 17 years of experience in well servicing, completions, conventional drilling, coiled tubing, well testing and underbalanced drilling. A former Shell Expro staff engineer, he was a member of the Shell U.K. / Deutag UBD development project from its inception, in an engineering and project co-ordination role. Instrumental in working with UBD service companies and the HSE in development of UBD technology for North Sea applications, Mr. Radcliffe has been a specialist / project co-ordinator for several studies performed by Deutag.
Copyright © 1999 World
Oil |
surface fluids
handling system is fundamental to underbalanced drilling (UBD) operations, because it
controls well influx and separates injected gas, reservoir products, drilling fluids and
drilled cuttings within a closed, pressurized environment. However, to increase efficiency
and provide necessary solutions to severe weight and space restrictions and zonal
classification criteria offshore, a fresh design approach was required. This design moved
away from large horizontal separation systems to vertical designs, which offer similar or
enhanced separation capability within a smaller footprint. 
