Low sulfate water injection knocks scaling off production hit-list

Deviated wells heavily impacted by scale

Jeremy Beckman
Editor, Europe

Scale formation brought on by reservoir waterflood can severely damage production wells, flowlines, and associated topside equipment. Remedial work is unending; on some North Sea wells, the situation demands injection of inhibitors every three days.

This antidote works to an extent on conventional vertical wells. It is far less effective on the growing legion of subsea horizontal or deviated wells, where correct placement of chemicals remains uncertain. On deepwater wells, squeezing is also costly, as it demands use of a specialist intervention vessel.

The least fraught solution may be to stifle the problem at its source through fitting a sulfate reduction package on the production installation. This can cause development CAPEX to balloon, but the investment should be retrieved through problem-free production.

Marathon was forced to initiate the technique in 1987 to avert a catastrophe at its North Sea Brae production complex. The incompatibility of the local seawater, containing sulfate, mixing with Brae formation water (containing barium/strontium) triggered investigation of membrane technology dating back to the 1940s.

Following prototype system tests in San Diego, Marathon put in a 40,000 b/d test plant in the South Brae platform in 1988, incorporating a Dow Filmtec NF40 membrane. The technique was proven when the flood front broke through with no subsequent loss in reservoir yield.

Hitch-free production thereafter encouraged Marathon to install Dow's new SR90 nanofiltration membrane on South Brae in 1993. This was designed to increase seawater processing rates at lower temperatures. Today, the system processes 120,000 b/d of injected water both for Brae and Lasmo's third party Birch Field.

Following South Brae, Marathon decided to patent the process, using Dow initially as its sole technology supplier. But as Dow was not a system manufacturer, Weir Westgarth in the UK was approached to handle the potentially strong North Sea market. The breakthrough came in 1990 when Agip UK's Tiffany Field became the first greenfield site to be selected for sulfate removal from injection water. The Tiffany platform package, operational around three years later, currently processes 100,000 b/d of low sulfate injection water.

Marathon then found a new application - countering scale on its Ewing Bank 873 gravel packed completions caused by 400 mg/l barium levels in the formation water. Historically, the tactic has been to squeeze gravel packed wells, but with dubious success - lost productivity is usually arrested, but not restored.

A 20,000 b/d low sulfate water package was specified for the field in 1994, expandable to 40,000 b/d. System design, as with the rest of the Gulf of Mexico currently, was handled by US Filters. Another package was subsequently fitted to Texaco's Petronius compliant tower topsides.

Outside North America, Weir Westgarth's services have been retained by Dow, but worldwide, the leading sub-licensed OEM for this technology is probably Axsia Serck Baker's membrane division, based in Gloucester, UK.

Axsia tailored a sulfate reduction package for BP's ETAP development and has now produced one for Kerr-McGee UK's Janice A, the first FPSO "guinea pig" for this technology. On these two projects, applications have broadened to include dilution water in HT/HP environments, horizontal wells, and subsea tie-backs.

Axsia offers its own analytical laboratories in the UK on top of a conceptual and detailed design and engineering service for each project. Pre-treatment includes deaeration and the use of coarse and fine filters. "The oil industry doesn't like filtration systems because they are heavy and take up a lot of space, but there are no alternatives," says Axsia's John Colburn.

On ETAP, the de-aerated sulfate reduction package will supply low sulfate water to Shell's Heron cluster oilfields. The wells are high pressure, high temperature with salinity formation waters thick with barium, strontium, calcium and sodium. According to Colburn, "for every 10 bbl of water produced, we have pulled out 50 bbl of salt."

Halite scale formation is therefore probable during production, but the thermal stability of scale inhibitors is not proven at the temperatures and pressures predicted on ETAP. In this case, the formation water will be diluted via injection into the production manifold, to permit mostly continuous output from the fields. The membrane system has been designed to be cleaned every 12 weeks, twice as long as the maintenance intervals on the South Brae and Tiffany platforms.

How it works

Despite the proven results of sulfate reduction, some producers are more focused on the price of the process package. Marathon calculates a total outlay of 8.2 cents/bbl of de-sulfated water injected into South Brae, which includes chemicals, power, filter and membrane replacements. These costs can be reduced, Marathon claims, through cuts in scale inhibitors downhole and in topsides components.

Also, workover operations such as pulling of tubing and scale milling by an NORM-authorized contractor are eliminated. A typical South Brae workover costs $1.5 million - normally two operations suffice per well each year. And costs savings of de-sulfated compared with untreated water are approximately $800,000 per well annually, Marathon claims.

In addition, the technique is more effective than conventional barite scale methods such as under-reaming on coiled tubing, jetting, pipework extraction and milling - all of which incur deferred production.

In broad terms, the system works as follows. Sodium and chloride, the most prevalent ions in seawater, are admitted through the membrane - however, the sulfate ion, which causes scaling when combined with barium, is removed. Maintaining the sodium chloride levels in the injection water in turn maintains reservoir salinity, preventing particle swelling, and consequent oil flow disruption.

According to Marathon, a typical sulfate reduction package provides a conversion rate of seawater feed to de-sulfated water of 75%. The SR90 nanofiltration membrane limits sulfate levels in injected seawater of 2,500-3,000 mg/liter to less than 50 mg/l at 20 barg. SR90-400, the latest version, offers the same performance but with 25% extra membrane surface area per element.

The SR90 is a thin film composite membrane comprising a very thin barrier layer made from a cross-linked aromatic polyamide which is reacted onto a micro-porous polyulfate support and attached to a reinforced fabric to provide strength and durability. Porosity/diffusion characteristics determine which ions are rejected or allowed to pass through. To ensure trouble-free operation of the membrane, pre-treatment is administered which includes:

Removing suspended solids bigger than 5 microns to ensure free flow of feed seawater within the spiral wound configuration
Dechlorination of the feed water, using sodium bisulfate, before it reaches the membrane
Destruction of biological organisms by chlorination
Addition of anti-scalant to prevent sulfate salts exceeding their solubility limits at roughly 5 ppm.

Floating production

According to Axsia Serck Baker, squeeze treatments/well workovers for scale control are not conducive to deepwater production through subsea well tiebacks. Problems include:

Logistics of scale inhibitor supply at these deep and normally remote locations
Cost of tubing strings
Expense/difficulty of performing workovers
Protecting production equipment.

Kerr-McGee Oil (UK)'s Janice development in 300 ft of water is not deep, but some of the factors listed above also led the operator to choose sulfate reduction - as a final resort.

The UK North Sea accounts for 40% of the company's worldwide oil output of 68,600 b/d. Much of that comes from the Gryphon Field, location for the North Sea's first monohull FPSO. Here, water from an overlying aquifer is injected into the reservoir. The produced water also is compatible with the reservoir water. Sulfate levels are low, so there is no scaling problem.

For Janice, a 70 million bbl oilfield in block 30/17a, Kerr-McGee and its partners have bought a semisubmersible flotel which is being converted for peak production of 55,000 b/d. First oil is due out this summer, exported through a new pipeline to Phillips' Judy platform, which is linked to Teesside, UK via the Norpipe system. Associated gas will be fed into the CATS transmission network.

According to Kerr-McGee's Mike Mansell, six to seven subsea producer wells will be drilled - all except one horizontal - along with four horizontal water injector wells. Water injection is mandatory to maintain pressure and to sweep oil to the production wells.

It turns out that the formation water contains large amounts of calcium - 10,000 mg/l - while seawater contains 2,860 mg/l of sulfate ions. So, wherever the injected water mixes with reservoir water, severe anhydrite (calcium sulfate) deposition could result. This would occur in the completions and tubing. Some carbonate deposition also could be expected.

"We thought of using a low sulfate underlying or overlying aquifer," says Mansell. "But we couldn't find one drilling through the entire sequence of rocks. And the deeper you get, the higher the amount of dissolved solids in water. Too deep, and the wells also become too expensive.

Re-injection

"Then, we thought about produced water re-injection - there will be substantial water cut on Janice anyway in four years. But as stated, the produced water is not compatible with the seawater, and we do need seawater to make up the volume. We also considered a separate system for re-injecting produced water in individual wells, however that looked too complex to be practical."

With seawater seemingly the only practicable injection medium, Kerr-McGee's first thought was to apply inhibitor squeeze treatments, a common practice in the North Sea. "But the problem on Janice is that our wells are both subsea and horizontal, making it difficult to place inhibitor in the right part of the completion interval."

Another option was conventional subsea wells, but that would have brought unacceptably lowered flow rate and recovery, plus higher well numbers, pushing up already steep drilling costs.

That left no alternative but seawater sulfate reduction. According to Mansell: "It's costly in terms of upfront CAPEX, and it takes up a lot of weight and space." Both looked to be at a premium on the Janice semisubmersible, even with the entire accommodation area stripped off the main deck. With a 160-ton sulfate reduction package to fit in as well, the vessel looked to be near its carrying capacity limit - and it also represented an extra piece of kit to maintain.

"The advantages," says Mansell, "are that it allows use of horizontal wells without scaling problems, avoids remedial workovers on subsea wells and it cuts the cost of scale inhibitor chemicals that would otherwise have to be used liberally. We hope, therefore, to increase our production uptime." That's also important in view of the partners' long-term plans to use the semisubmersible as a production hub for future developments in the area.

The package, designed by Axsia Serck Baker and built by KYE in Lowestoft, UK. It is due to enter service by September, producing 70,000 b/d of injection water.

The process works as follows: First, the sulfate reduction process is fed with seawater, which is then treated in a multi-media filtration system and also with cartridge filtration before entering the membrane system. The low sulfate product stream is then injected into the subterranean oil-bearing reservoir.

Reservoir souring

Another so far unexploited benefit of low sulfate water is the potential reduction of hydrogen sulfide formation following breakthrough of injected seawater, through denying sulfate-reducing bacteria their main source of nutrition.

Tests on low sulfate water by CAPCIS in Manchester, UK found that resultant sulfate to sulfide conversion was cut 98% to 18 ppm. Recent studies by AEA Harwell, UK confirmed that if this were the case, the reservoir rocks could mop up by themselves the residual hydrogen sulfide. In that case, no hydrogen sulfide should reach the production wells during the field's producing life, so souring should not occur. In turn, that eliminates the need, in theory, for exotic metallurgy.

As Axsia Serck Baker's John Allinson points out: "On deepwater TLP risers, where thick steel tubes are needed, the ability to lower NACE standards could bring significant cost savings. We will therefore see sulfate removal packages more and more on FPSOs, TLPs, and Spars."