In-Line-Water-Separation Prototype Development and Testing
- Karen Bybee (JPT Assistant Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 2011
- Document Type
- Journal Paper
- 84 - 85
- 2011. Society of Petroleum Engineers
- 0 in the last 30 days
- 70 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||Free|
|SPE Non-Member Price:||USD 17.00|
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 137967, "Inline Water Separation (IWS) Field Prototype Development and Testing," by J.J. Xiao, SPE, and Ramsey White, Saudi Aramco, and Shoubo Wang and Luis Gomez, Multiphase Systems Integration, originally prepared for the 2010 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 1-4 November. The paper has not been peer reviewed.
A compact multiphase in-line-water-separation (IWS) field prototype system has been developed and tested. The system consists of a gas/liquid cylindrical cyclone (GLCC), a liquid/liquid pipe separator (LLPS), a liquid/liquid cylindrical cyclone (LLCC), and two-stage liquid/liquid hydrocyclones (LLHCs). The function of the system is to separate a significant portion of the produced water from a production stream while the remaining production fluids are sent to existing processing facilities.
As oil fields mature, more water is produced with the oil and gas production. This is especially true when water injection is used to maintain reservoir pressure and increase oil recovery. A common production-water-handling strategy is centralized processing. In this scheme, production from individual wells is gathered to manifolds through flowlines and is transported to the gas-/oil-separation plant (GOSP) through large-diameter trunklines. At the GOSP, separation and processing of oil, gas, and water take place with large conventional vessels. The processed water is either disposed of at nearby water-disposal wells or sent back to the field for water reinjection into the reservoir. With increasing water production, several issues can develop:
- Water volume exceeds water-handling capacity of the GOSP, which can cause processed water to be off specification. The off-specification water in turn can lead to a decline in water injectivity, which may require regular stimulation treatments. Upgrade or expansion of GOSP water-handling capacity with conventional bulky separation systems can be costly.
- Existing gathering systems can become a bottleneck to oil production. To maintain oil production, the total fluid produced will increase as the water cut increases, and the gathering-system capacity will become a limiting factor. Laying extra flowlines or trunklines can be expensive, especially offshore.
- Wells can cease to produce because of increasing system backpressure as a result of the increasing water volume being transported through the gathering systems.
- Higher water production leads to higher chemical use (demulsifers and corrosion inhibitors) and, hence, higher processing cost. In addition, energy consumption will increase to transport large quantities of water from the field to the GOSP and then from the GOSP back for reinjection into the wells in the field.
A number of methods are used to reduce the quantity of water produced to the surface. These methods include restricted production, cyclic production, mechanical or chemical water shutoff, and short-radius horizontal drilling. For new wells, the use of production equalizers and smart completions also can be viewed broadly as a way to control water production. The next-best place to handle water production is in the wellbore. However, downhole oil/water separation and reinjection still remain a challenge even after 20 years of industry research and development.
|File Size||93 KB||Number of Pages||2|