Drilling & Production

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In August of 2003, these wells were identified as liquid loaded. One of the wells was shut in, and the other was producing intermittently. The operator needed an economic solution that would allow the wells to produce with a reduced wellhead pressure (WHP) to unload the fluid column from the loaded-up wells. Glen said that the restored production from these wells would translate directly into increased reserve recovery of the field. Several options were considered, including the installation of a conventional low-pressure (LP) system (that would require a gas compressor), an LP separator, and liquid pumps. Associated high capital expenditures, space requirements, and potential increase in operating expenses led to an ultimate decision against this option.

The booster system was introduced as an alternative to the conventional process of adding a separator, compressor, and pumps. This system would essentially operate as the intermediate-pressure (IP) or LP production system needed to help boost the non-producing wells by creating a low-pressure suction to which both wells could flow, Glen said.

The first well was a liquid-loaded satellite gas well that was producing a high volume of water before loading up. According to Weatherford, a well in this condition becomes problematic as water cut increases and bottomhole pressure declines. Eventually, as the well experiences short-term shut-ins, resulting from process upsets or monthly equipment testing, unloading the well to the high-pressure (HP) system becomes increasingly difficult. The operator was no longer able to restore the well to production in the HP system operating at 1,150 psig, and it remained shut in. Upon installation of the RamPump, the well was unloaded continuously at 300- to 400-psi suction pressure. In less than a week, the well started making enough gas at a high enough flowing tubing pressure (FTP) to allow disconnection of the multiphase booster and to flow naturally into the HP system, Glen said. Once unloaded, the well continued to produce at rates of 3,168 Mcf/d, 129 BOPD, and 877 bw/d, with a 2,550-psig FTP. Newfield can now divert this well into the same system, as needed, if the well loads up during any unscheduled shut-in period.

In another case, where low bottomhole pressure prevented a well from flowing into the HP system, the A-15 well was directed to the booster system operating at a suction pressure of 450 psig, which boosted the flow into the HP system at 1,150 psig. By early October 2003, the well was producing 1,969 Mcf/d, 7 b/d of condensate, and 2 b/d of water, at 920-psig FTP. The multiphase booster continues to produce this well at the reduced WHP and boost flow to the HP system.

Multiphase pumping lowers WHP and minimizes equipment requirements by creating a low-pressure zone between the well and the high backpressure source, such as a long flow line or downstream separator, said the company. This technology is used to lower backpressure in flow lines from wells and production gathering systems, or to boost pressure going into higher-pressure discharge flow lines. It is most beneficial to production companies that do not have the space to install separators, flash tanks, compressors, liquid pumps, and vapor recovery units but still want to achieve lower operating pressure to maintain or improve production.

Multiphase pumping could also be useful in special industrial applications with low net positive suction head available, such as operations with fluids at flash point and operations using compressible fluids with entrained gas, which could damage conventional pumps.

According to the company, multiphase booster system is a vertical, long-stroke, duplex-piston positive-displacement pump that reciprocates using hydraulic cylinders actuated by a hydraulic power unit (HPU). The HPU design allows the pump to handle flows ranging from wet gas streams to 100% liquids, which covers a broad range of viscosities and densities. The pump can also manage flow streams that contain periodic slugs of fine solids, such as sand or silt. The HPU allows the pump to provide a 0 to 100% turndown of the flow volume, a benefit that most multiphase pumps are unable to offer, even with a variable frequency drive (VFD) or conventional compressors operating in recycle mode. The HPU, driven by a gas engine, diesel engine, or electric-motor prime mover, can be mounted on the same skid or on separate skids to meet space and crane lift weight limitations. This flexibility allows for future interchangeability of various pump systems and HPU sizes as conditions change.

Typically, discharge pressure for a 12-in. pump for HP applications is up to 1,200 psig but can be rated as high as 2,000 psig if required, the company said. Sizes up to 16-in. plunger diameter can also be rated up to 900 lb ANSI with up to 2,000-psig discharge. Both the pump and its seal system are fully rated, statically and operationally, for ANSI class 300-, 600-, or 900-lb pressure levels, depending on the system requirements. Units up to 20 in. in diameter are limited to 600 lb ANSI, and 24- to 32-in. units are typically rated at 300 lb ANSI.

Newfield says that a single RamPump unit can eliminate the need for separators, compressors, pumps, and vapor recovery systems at remote onshore well sites or offshore platforms, thus saving space and capital.

High-performance drilling fluid

A new high-performance water-base drilling fluid has been introduced by Baker Hughes Inteq Drilling Fluids. The Performax fluid is designed to deliver the drilling characteristics of emulsion-base drilling fluids without sacrificing environmental compliance. According to Baker, benefits include improved shale inhibition (reduced pore pressure transmission), increased cuttings integrity, increased rates of penetration, and reduced torque and drag.

Since its introduction last year, the fluid has been used on a broad range of drilling applications including onshore, continental shelf, and deepwater projects. A few highlights from these wells include penetration rates averaging 90 ft/hr (28.6 m/hr) with both PDC and rock bits, low dilution rates and high solids removal efficiency, friction factors equivalent to emulsion-base mud, minimum bit balling and accretion, elimination of rig set-up and waste management costs associated with emulsion muds, and significant rigtime savings during clean-up for completions versus emulsion muds, Baker said.