Several North Sea fields anticipate extended treatment life and reduced oil deferments.

Three subsea oil production giants are trying to unlock the full potential of the reservoir. Over the past 5 years, the Ondeo Nalco Energy Services Division has partnered with BP Exploration and Shell UK Exploration and Production to test a new chemical delivery technology that should help oil producers achieve longer, uninterrupted oil production. The system, which controls depositions, corrosion and reservoir souring, aims to improve conventional methods of protecting reservoir and production tubing from problems such as scale, corrosion and bacterial growth.

The emulsion technology, known as the Access system, increases the effectiveness and longevity of chemical treatments required to prolong the life of well tubulars. Application carries fewer risks than conventional aqueous treatments because the system enables more rapid cleanup of the well and minimizes damage to the near wellbore area. The system has proven effective in difficult subsea environments, horizontal wells and sensitive reservoirs.

History of the technology

BP developed the emulsion scale inhibitor technology in 1998 at its Sunbury Research and Development labs in the UK. The technology was originally intended as an alternative to oil dispersible and oil soluble scale inhibitors that can be applied in low water cut wells to enhance lift ability, allow for rapid well cleanup and reduce the risk of clay swelling and fines mobilization.

BP investigated various emulsion-based systems and application techniques. Out of these, the Acess system showed the greatest potential in early laboratory tests. BP partnered with the Ondeo Nalco Energy Services Division in applying the technology in the Forties, Gyda and other North Sea oil fields, as well the Milne Point field in Alaska. The technology has also been used in ChevronTexaco's Strathspey field and two Shell North Sea oil fields. The fields being tested have a wide range of water cuts, ranging from 2-5% at Milne Point field, to 95-97% at the Strathspey field.

Ideal uses

Several labs have assessed the emulsion technology's potential to reduce formation damage and extend squeeze life times. To date, the technology has been evaluated in two different applications:
• low water cut or dry wells where treatment can be applied as soon as the well is completed, or at initial water breakthrough; and
• higher water cut treatments at more than 20% water cut.

While the chemical delivery system is not ideal for all applications, it is beneficial for sensitive clay formations (oil external micro-emulsion) when fines mobilization or clay swelling can be promoted by aqueous solutions. It is also beneficial when relative permeability is such that water trapping and oil permeability loss would occur after an aqueous solution is applied.

The treatment system can have an advantage when regular squeezes don't last very long due to poor adsorption or precipitation. The system is also useful in cases when it is difficult to lift water out of the well to clean it up and restore production (e.g. where artificial lift is needed.)

How it compares

The treatment is used to squeeze or batch treat production wells. It allows for the slow release of scale inhibitors and provides protection against scale formation for extended periods. Treatments can last three to four times longer than regular scale squeezes. Compared to conventional treatments, the system's benefits are wide-ranging:

• no shut-in time is needed, so there is no lost production;
• if diesel is used to push the treatment fluid, the well usually cleans up quickly (1-4 days instead of several weeks);
• the treatment's relatively high viscosity supports even distribution along the producing interval of horizontal wells offshore, particularly if it is necessary to mobilize a vessel to do a regular squeeze;
• companies can drill the well and place the treatment in the formation before they even start production, and most of it will remain in place until water starts to break through much later (such pre-emptive application is suitable for subsea wells that are a significant distance - up to 12.5 miles (20 km) - from the platform);
• the treatment has been bullheaded from the well platform down a 4-in. gas lift line and 33/4-in. umbilical lines.

Counterintuitive aspects

Proper lab testing, including analysis of core floods, should be undertaken when operators consider using this treatment in order to assess the potential of well formation damage. Data from these studies suggest that changes in oil and brine permeability are minimal, and that the chemical poses minimal risk to the well formation.

Operators should also consider using it for fractured chalk production wells, because they need protection from scale formation once they produce water. The treatments, when used preemptively while a well is producing no water, offer a route for protection and could be incorporated during well completion/fracturing.

Conventional aqueous squeeze treatments return high concentrations of often-acidic scale inhibitor over a short period. Such residue can upset the process. In contrast, the Access treatment returns at much lower concentrations in the aqueous phase, a phenomenon that does not seem to affect water quality. The physical form of the returns may also be a factor. Moreover, problems with producing emulsion and treating topsides, arising after conventional treatments, do not present a problem with the alternative system.

The emulsion's character

The chemical treatment is made through high shear mixing of an aqueous phase, including the active scale inhibitor, with a hydrocarbon phase (i.e. odorless kerosene with an emulsifier).

The system is manufactured onshore and then shipped to fields that are typically offshore in the North Sea. It is mixed so that droplet size is less than 2 microns (specs: 95% < 3 microns) and should be used soon, or else the micro-emulsion may need some re-mixing after sitting for a long period of time. (See table for exact details of particular treatments.)

The treatment is normally pumped undiluted with an additive-free diesel pre-flush and followed by an over-flush to displace the chemical into the near wellbore area. The over-flush can vary in type, but additive-free diesel often has been used. Gas also has been used periodically.

Case history: deployment

Four remote, high-producing oil-production wells in a subsea oil field have been treated using this technology for scale control.

To overcome the traditional challenges of deploying chemicals to inhibit scale in high permeability reservoirs, the scale inhibitor package was applied as a viscosified fluid with viscosified over-flush to enhance the placement of the chemicals.

Deployment of the technology in the four high-permeability wells did not require coiled tubing to aid in placement. Scale squeeze treatments were achieved by way of a 12.5-mi. (22-km) gas-lift line, which reduced treatment costs in comparison with a conventional DSV bullhead application.

In three of the four production wells, rapid well cleanup was observed. One well was impaired as a result of applying the emulsion chemical, with its productivity index reduced by half. The impairment is believed to be a result of fines mobilization, as fines migration had manifested itself in this well 6 months before the squeeze. Such mobilization of fines may have been a more significant problem if an aqueous treatment had been applied.

In addition, no significant upset to the topside separation process was observed during well flow-back. It is difficult to ascertain whether this chemical delivery system increased chemical-treatment lifetimes, since no aqueous squeeze has been performed, but the protection of almost 1,000,000 bbl of produced water to minimum inhibitor concentration, equivalent to 10 months of production, is good performance for such a reservoir.

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