The petroleum industry has relied on conventional production facilities tech nology for a low-risk approach to life-cycle operations. However, industry motivations to offset the combined effects of the current downturn and volatile oil price find operators now evaluating production technologies that impact the bottom line.
Eager to drive down costs while creating avenues for frontier development, operators are looking at ways to increase production capacity on existing facilities and new installations. Improved utilization of space and systems and optimized facilities design using separation technology are expected to create new development opportunities, particularly in the promising deepwater arena.
Interestingly, production facilities design may be as critical to the industry's success in the new millennium as fast-tracking has been to activities in the 1990s. Fast-track developments have significantly rejuvenated the upstream oil and gas industry, allowing oil and gas fields to come on stream sooner, thus improving an operator's rate of return on investment. The demand for fast-tracking has led to changes in the execution and project management of production facility projects. However, in almost all of these fast-track approaches, production facility design has adhered to conventional separation technologies.
New developments in separation technology provide an attractive alternative to conventional gravity separation methods that increase topsides weight and consume large amounts of space. Pop ular applications for new separation technology, which is lighter in weight and often more compact in its installation, include de-bottlenecking existing facilities to accept additional production from new wells and planning minimum-weight surface facilities for deepwater developments. Many of the new technologies, because of their reduced equipment size, also are suitable candidates for downhole and subsea processing. - A downhole oil-water separation system has been successful only in water continuous phase.
Upstream production facilities are designed to separate oil, gas and water. Figure 1 shows a block diagram of a standard surface facility and the conventional separation devices used. Primary separation equipment provides bulk separation of the oil, gas, and water. Gas passes through scrubbers before it is compressed, dehydrated, and sold via a pipeline. Oil is dehydrated to meet sales specifications and sold via pipeline, while water is treated according to regulatory requirements for appropriate disposal. Relief or flare systems are provided for safety.
In some facilities, bulk water is separated and injected back into the reservoir or gas is injected into the reservoir for gas-lift or pressure maintenance. In other cases, removal of solids (sand) from the production requires special equipment.
Conventional gravity separation uses the force of gravity to affect separation. Since oil and water have different densities, the force of gravity causes the more dense substance to fall to the bottom of the separation vessel while the lighter, less dense liquid rises. - A downhole oil-water separation system has been successful only in water continuous phase. - Subsea separation is another frontier to relieve backpressure on wells, increase flow assurance, and move production longer distances from surface facilities.
Gas, being the least dense of the three phases, rises to the top of the vessel. Conventional separators are generally cylindrical-shelled vessels that are either horizontal or vertical in orientation. Figure 2 shows a typical conventional horizontal three-phase separator.
The size of a conventional separator is indictated by the amount of time, known as "retention time," needed to accomplish gravity separation. The retention time is directly proportional to the volume that must be contained in the vessel and, therefore, the vessel's size. In a gas-liquid separator, a certain amount of time and liquid storage space is required to assure that the liquid and gas reach equilibrium at separator pressure.
Another factor in separator sizing is the settling velocity for liquid drops entrained in the gas. In oil-water separation, additional retention time is needed for "free water" to coalesce into droplets large enough to fall to the oil-water interface.
New separation technology enhances gravity separation or uses other techniques to allow separation in smaller cylindrical shells or areas. While some of the new separation technologies can be used in combination with existing separation systems, creating hybrid systems to enhance effectiveness, other technologies are intended as stand-alone devices. The technologies are categorized as follows:
- Centrifugal force using production stream pressure: The cylindrical shell or vessel is fitted with internals that use stream pressure to swirl and rotate the incoming stream or production. This configuration produces centrifugal force in the order of one-thousand times the force of gravity, thereby increasing the speed of separation. Long retention times are lessened, resulting in the reduced size of a separation vessel. Examples of these are centrifugal separators and hydrocyclones. Figure 3 shows the internals of a typical centrifugal separator.
- Centrifugal force using external power source: Centrifugal force, as discussed above, also can be achieved by rotating shaft or vessel internals using an external power source. A typical example of this is a centrifuge.
- Special internals for separation: These devices can increase the surface area for coalescence of oil droplets, thereby enhancing gravity separation. Known as high-performance internals (HPI), these devices are generally used in primary separation and water treating.
- Special internals decreasing turbulence: Some internals reduce turbulence and create quiescent conditions within the vessel to improve separation. These devices are generally used for primary separation where slugs of liquids may cause turbulence, decreasing separation efficiency.
- Induced gas: This method involves the sparging or bubbling of gas into a vessel containing produced water. Fine bubbles sweep the liquid, collecting oil droplets that are transported to the surface and removed. This application is best applied in water treating.
- Electro-pulsed high-energy field: A high-voltage DC electro-pulsed field causes water droplets to coalesce into larger droplets, thus increasing the potential for easy separation. This method is used in the oil continuous phase in applications such as oil dehydration.
- Special absorption material: Some absorption materials absorb oil from produced water before water disposal. These materials are generally used in temporary applications when additional water treatment is required to meet regulatory requirements.
- Downhole technology: Some methods allow for separation in downhole casing. The application could be bulk water removal for water injection or liquid-gas separation for gas injection. Separately, downhole multiphase metering technology allows an operator to monitor reservoir performance and optimize well production.
- Metering without separation: Meters that measure gas, water and oil without separation can eliminate the need for a test separator on the facility.
- Metering after gas/liquid separation: Some metering technology measures oil and water, which are separated from gas without requiring further separation. Gas/liquid separation is generally achieved with centrifugal separators.
For surface applications, new technology can be used to effectively de-bottleneck existing facilities for increased production capacity and to improve planning for topsides facilities in deepwater installations.
New separation technology has particular merit for deepwater topsides. A recent study at Paragon shows that savings are greater in heavy oil production, where conventional technology demands the use of large vessels. In such cases, a reduction in topside space and weight requirements for tension leg platforms, spars, and others can reduce capital cost enough to warrant the risk of the using new technology.
Another application calls for de-bottlenecking of existing offshore facilities because of space limitations. Specifically, use of special internals for existing vessels can increase throughput, without requiring additional space.
Portable skids, which can be easily moved and re-deployed for onshore or offshore use, also are advantageous because of their compact size. This approach is particularly effective in remote areas of the world where industry infrastructure is not readily available.
Subsea processing and separation presents another frontier. Figure 4 shows the subsea separation system. The use of subsea separation is primarily motivated by:
- Need to reduce backpressure on the wells to increase production
- Need to increase flow assurance, particularly for three-phase flow systems
- Longer distances between proposed subsea wells and a central production facility.
A misconception regarding subsea separation is an expectation that topside facility requirements will be dramatically reduced. This point is debatable because subsea operations require additional support equipment. For example, the supply of power subsea may force the facilities to include larger generators, thereby adding substantial weight and space requirements.
Further, subsea separation does not eliminate weight-consuming and space-consuming equipment such as compressors, oil treaters, and dehydration equipment. Performance reliability is another major issue impacting subsea development. The operational risks involved in subsea separation must be balanced against the technology's potential to increase production and improve flow assurance in deepwater developments.
Downhole separation is usually focused on bulk oil-water separation and injection of water in the reservoir. This application is commonly referred to as DOWS (downhole oil-water separation). Figure 5 shows a schematic of this configuration. However, DOWS has been successful only in the water continuous phase and, as in subsea applications, reliability issues arise. The key advantages include a reduction of energy required to lift water and the use of the same borehole for water injection.
Technology for production separation facilities is rapidly evolving and improving, with new products continuing to be developed. However, operators are hesitant to integrate non-conventional technology into a facilities design system until success rates and performance levels of new devices are properly measured and observed. Regardless of improved capital and operating costs, "life-cycle" cost remains an unknown factor until industry has more data from actual applications and installations.
The "life-cycle" cost impact, due to a change in operations philosophy or equipment reliability, may lead to frequent shutdowns. This potential imposes significant risk on oil and gas production contracts based on high-availability of the facility. Meanwhile, new production technologies hold promise for improved field economics for surface facilities, subsea development schemes, and downhole applications.
For surface applications, the trend has been mostly limited to de-bottlenecking, where oil companies have been more willing to take risks. As the operability of equipment becomes established among existing facilities, their inclusion in new design will become more acceptable.
As far as specific systems, water treating has been the most open to new technology because it is driven by mandatory government regulations. Well testing and metering are other areas where new technology has made inroads because testing does not require continuous operations.
In addition to accuracy, capital cost has impacted new technology in well testing. For onshore facilities, portable meter skids have become economical because of the flexibility to use the systems at various nearby facilities.
In oil treating, oil companies have been receptive to new technology for heavy oil applications where conventional technology has had difficulties in meeting oil specifications. The use of this technology in primary separation has been lagging because changes in primary separation systems greatly affect operations as a whole.
The area of subsea processing holds the greatest opportunity for improved cost benefit and flexibility in field development planning. Future concepts for installing separation facilities on the seafloor at the wellhead site are expected to decrease flowline pressure and enable improved production. In the past, subsea processing experiments have involved the use of conventional, bulky gravity separation equipment. New technologies, however, have created opportunities to minimize equipment sizes to make subsea applications economically viable. While subsea processing is still in the testing phase, subsea multiphase flow metering is in use and represents proven technology.
Downhole oil water separation (DOWS) has been used in about 100 onshore installations. Because of performance and reliability issues, however, the industry has not yet applied DOWS technology offshore.
Lately, the industry has explored the design and experimental use of liquid-gas separation downhole, with downhole gas injection and reduced wellhead pressures becoming advantageous. Downhole metering for immediate reservoir monitoring to optimize production is another arena with increased interest.
In most cases, new technology separation equipment is advertised and compared with conventional equipment on an individual basis. While weight and space savings, along with decreased capital cost, may look attractive, new equipment may cause changes in operations philosophy and impact field development economics.
For example, increased shutdowns and downtime caused by using a new technology might absorb any savings, making a critical review of technology concepts within the perspective of a facility's "life-cycle cost" imperative.
While new separation technology is present ly overshadowed by reliability and operation requirements, increased experimental use of various applications is expected to improve economics and offset industry risks in the new millennium.
Sandeep Khurana, P.E., is a facility engineer with Paragon Engineering Services, Inc. and offers more than 10 years of diversified experience in the offshore industry. He holds a MS degree in civil engineering from Rice University.
José M. Torres is a member of the marine pipelines and subsea group at Paragon Engineering Services, Inc. He holds a BS degree in maritime systems engineering from Texas A&M University.
Patti L. Ferguson is a facility engineer at Paragon Engineering Services, Inc. He holds a BS degree in chemical engineering from Lamar University.
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Arnold, K., Ferguson, P.,"Designing Tomorrow's Compact Separation Train," SPE 56644, October 1999.
Singh, B., "Subsea Separation: A Perspective," Deep Offshore Technology Conference, Stavanger, Norway, October 1999.
Veil, J., Langhus, B., Belieu, S., "Feasibility Evaluation of Downhole Oil/Water Separator (DOWS) Technology," Preliminary report prepared for US DOE under Contract W-32-109-Eng-38.