From Brazil’s Tupi field to the South China Sea, in water depths greater than 5,000 ft (1,500 m) and with target formations at 10,000 to 30,000 ft (3,000 m to 9,000 m) below the mudline, ultra-deepwater developments are an enticing new frontier for both operators and service companies. Deep offshore undiscovered and inferred reserves account for 49% of North America’s offshore natural gas resources and 65% of its offshore oil resources. However, these high-value properties need new completion and stimulation technologies to make them economical and to maximize resource recovery.

Saving days of rig time by enabling stimulation of several zones in one trip, BJ Services personnel run the ComPlete MST system into a well offshore Indonesia. (Image courtesy of BJ Services)

Even in less challenging offshore wells, high bottomhole pressures and temperatures, corrosive fluids, and long pay intervals have sparked development of new stimulation vessels, tools, and fluids, with much more under way. Now, as water and well depths increase, downhole tool systems that were typically rated for 10,000 psi (68 MPa) differential pressures a few years ago are now available to 15,000 psi (103 MPa), with rugged 20,000-psi (138-MPa) systems under design.

Rig costs are steep for these ultra-deepwater projects, so operators are eager to use technologies and services that save rig time without compromising safety or quality. In addition, technologies that minimize fluid, proppant, and chemical volumes simplify the logistics related to delivering materials far offshore.

Finally, workovers on these subsea developments are prohibitively expensive, so durable and reliable technologies are vital as are technologies that prevent common downhole problems.

Long-term HP/HT solutions are needed

The initial challenge for ultra-deep wells has been drilling and completions driven by the combination of pressure and temperature parameters. For example, wells in the Gulf of Mexico’s (GoM’s) Lower Tertiary play are expected to see initial bottomhole pressures of more than 20,000 psi and temperatures up to 400°F (204°C).

High-pressure/high-temperature (HP/HT)conditions for sand-faced completions can create a design nightmare. In addition to affecting material strength — which affects pressure rating — high temperatures can accelerate corrosion effects and increase the chance for stress cracking. Furthermore, the extreme depths increase stretch on tool strings, requiring engineering designs to address mechanical manipulations and precise tool placement during completion sequences associated with stimulation and production operations.

For these reasons, oilfield equipment for ultra-deep water must be redesigned based on rigorous evaluation to ensure that it is as reliable — or even more so — than prior generations of equipment.

The new CompSet II HP Ultra packer, for example, is functionally the same as prior CompSet packer technologies, but it was re-engineered for extreme conditions, achieving an ISO 14310 V0 rating at a differential pressure of 15,000 psi and temperature of 350°F (177°C).

The Ultra packer technology is designed to be used for gravel packing, high-rate water packing, frac packing, and stimulation. Packers and completion systems for even more extreme conditions are in the research phase, with operators looking ahead to developments that may see pressures up to 30,000 psi (207 MPa) and temperatures above 400°F.

Saving days of rig time pays off

To achieve economic goals, deepwater wells typically require long pay zones, which can be difficult to stimulate for several reasons:

? Safety. Perforating one long interval requires running hundreds of feet of guns.

? Reliability. Completion hardware must operate after being bounced, scraped, and manipulated through long deviated segments and then continue to operate as expected for the producing life of the well under harsh downhole conditions.

? Logistics. Rigs and stimulation vessels have limited space for fluids and proppant, which especially affects massive completions intervals.

? Economics. Rig time is expensive, and nonproductive tripping time through deep water adds up.

Operators avoid some of these issues by completing and stimulating long pay zones as several smaller zones using sequential stacked-frac packs. The new retrievable ComPlete FP DZ (frac pack deep zone) completion systems are designed specifically to achieve ultra-deepwater frac- and gravel-pack applications. Based on the CompSet II HP Ultra packer, the tools’ extreme design features include extended tool length and positive weight indications for changes in tool position.

To minimize the potential for erosion even in large high-rate stimulation and sand control treatments with abrasive proppants/gravels, the service tool position is the same in the squeeze and circulating positions. The system for larger casing (9 ?, 9 ? and 10 ? in.) has undergone 40-bbl/min (6 cu m/min) erosion testing with more than 1 million lb (450 t) of 16/30 bauxite. Such volumes of abrasive proppants are expected to be the norm for ultra-deepwater well stimulation.

Time-saving solutions are key

In many cases, conventional sequential operations are undesirable because they require many trips into and out of the well. As water and well depth increase, this nonproductive tripping time becomes a significant cost — often the bulk of the well completion cost. Instead, single-trip completion tools can save rig time by combining multiple functions.

For example, the ComPlete MST (multizone, single-trip) system uses patented technology to facilitate one-trip sand-face completions across multiple production intervals (Figure 1). The system has been used to rapidly complete more than 25 shallow- and deepwater wells in the GoM, India, and Indonesia, with as many as six zones isolated in one trip.

For example, in a deepwater GoM well, use of a 9 ?-in. version of the system allowed crews to complete the well and perform frac-pack stimulations in two distinct zones, with operations lasting only seven hours longer than previous one-zone completions in the same area. The operator estimated the system saved more than three days of rig time. Recent work in shallower water offshore Indonesia saved an operator more than 50 days of rig time while completing 16 zones in three wells with frac and gravel packs.

Stimulation equipment and fluids, scale-up to fit requirements

Pumping the stimulation treatments for these state-of-the-art wells requires state-of-the-art fluids and equipment. For example, the new Blue Dolphin stimulation vessel is the first 20,000-psi pressure-rated stimulation vessel specially designed for ultra-deepwater conditions. Its mission-critical hardware includes multiple ultra-high-pressure flexible umbilical lines, eight skid-mounted 3,000-bhp Gorilla frac pumps, and storage capacity for 2.75 million lb (1,250 t) of proppant; 1,885 bbl (300 cu m) of fluids, completion brines, and solvents; and 12,600 gal (48 cu m) of raw acid.

Even such high-horsepower surface equipment will be challenged to achieve frac pressures in ultra-deepwater wells without the help of weighted fracturing fluids such as the delayed-crosslink BrineStar family of fluid systems.

Compatibility testing of all drilling, completion and stimulation fluids is critical, as demonstrated by a recent GoM stimulation operation. While drilling a 10,500-ft (3,200-m) gas well, the operator lost more than 4,200 bbl (670 cu m) of synthetic oil-base mud (SOBM) to an underpressured zone.

After smaller losses had occurred on neighboring wells completed by another service company, the SOBM left in the formation combined with high-density completion brines and frac-pack fluids to develop emulsions that plugged the wells immediately after completion. Expensive remedial coiled tubing intervention eventually enabled sub-optimal 7.5 MMcf/d (212,000 cu m/d) production with more than 6,000 psi (41.4 MPa) flowing tubing pressure.

To avoid these problems in the new well, BJ Services performed detailed compatibility studies to select an economical but effective chemical and surfactant package — an optimized Paravan system — to prevent emulsions. This system was pumped as a component of all the fluid systems injected into the formation during the completion.

Initial well production was more than 10 MMcf/d (283,000 cu m/D) at low drawdown, which was better than the operator’s expected potential. After three months, the well showed no indications of emulsions, and no remediation or chemical treatment has been required. These factors significantly improved the economics of the well compared with the offsets.

In another innovative damage-prevention measure, BJ Services provides StimPlus services for long-term inhibition of common downhole problems such as scale, asphaltene, paraffin, and salt deposition and corrosion. For example, a GoM well that included ScaleSorb solid scale inhibitor in an April 2007 frac pack was still showing effective inhibitor residuals a year later in a well producing 3,500 b/d of water. To provide the same protection in sand-face completions that do not include fracture stimulation, BJ Services recently installed a completion system that included a screen prepacked with sand and 12/20-mesh ScaleSorb solid scale inhibitor.