mv Stim Star II — The newest addition to Halliburton’s GOM fleet (Brochure)

The Stim Star was designed to perform high-rate water packs, fracpack operations, carbon dioxide (CO₂) and nitrogen (N₂) treatments, acid treatments, and resinconsolidation operations. Figs. 1a and 1b are photographs of the vessel, and Fig. 2 is a diagram of the deck layout. The vessel has the following features:

pumps capable of 15,000-psi working pressure (WP)

50-bbl/min mini FracPac blender

above-deck proppant capacity of more than 650,000 lb

400-ft, reel-mounted, 3-in. high-pressure hose capable of accommodating an additional reel

remote, hydraulic quick-disconnect

automatic remote controls (ARC^®) for all operational procedures

process fluid pump redundancy

In addition, this vessel is equipped with a dynamic positioning (DP) system which includes anti-roll tanks and a computerized ballast-control system. Dynamically positioned vessels are capable of responding to drastically changing weather conditions. The DP system interprets environmental data and allows the operator to hold or change the vessel’s position accordingly. Consequently, the Stim Star can remain steady and in close proximity to deepwater rigs in swells as high as 15 ft.

Conventional Fracpack Treatments

Fracpack treatments involve creating a large fracture beyond the near-wellbore region. This fracture bypasses the damaged, restrictive area of the formation, expanding the effective radius of the wellbore. The enlarged wellbore radius helps increase flow rates and decrease drawdown, the difference between production pressure and reservoir pressure. Drawdown initiates the flow of hydrocarbons into the wellbore, but it can also destabilize the formation, causing fines and formation sand to migrate into the wellbore where they cluster, impairing conductivity and decreasing production.¹ In addition to increasing flow rates and decreasing drawdown, fracpack treatments help operators achieve better sand control, full zonal coverage in highly laminated reservoirs and nonperforated zones, and greater control of non-Darcy flow effects.

Delta FracPac System

Delta FracPac service includes use of a borate-crosslinked fracturing fluid with a low guar content. In recent years, borate-crosslinked fracturing fluids have become increasingly popular for the following reasons:

They provide excellent viscosity.

Borate systems reheal with minimal deterioration under shear conditions because the crosslinks continually break and reform.

Borate salts are inexpensive and occur naturally.

Delta FracPac fluid is different from conventional systems because it requires 20 to 25% less polymer loading. Consequently, potential formation damage from gel residue and filter-cake buildup is reduced. In addition, low-polymer gels can be broken more easily, facilitating faster, easier cleanup. The new Delta FracPac fluid formulation is environmentally acceptable in the GOM and offers these advantages:

enables offshore disposal without environmental risks

lowers disposal costs

Figs. 3, 4, and 5 compare the viscosity values of Delta FracPac fluid with those of conventional borate fluids at various temperatures.^{1, 2}

Fig. 3—Comparison of Delta FracPac (DFP) fluid to conventional borate fluids at 150°F.

Fig. 4—Comparison of Delta FracPac (DFP) fluid to conventional borate fluids at 170°F.

Fig. 5—Comparison of Delta FracPac (DFP) fluid to conventional borate fluids at 190°F.

Adaptation

In offshore operations, seawater is a costeffective base for fracturing fluids because it is plentiful and readily available. When fresh water is used, the vessel has to return to a base where it is reloaded. The time required for refilling fracturing-fluid tanks with fresh water can be as long as 12 hours. By substituting seawater for fresh water in offshore jobs, operators can significantly reduce their overall completion costs.¹

In the past, operators were reluctant to use seawater with fracturing fluids because of the potential problems associated with fluid incompatibility and the precipitation of magnesium salts. However, Delta FracPac fluid has been adjusted to overcome these problems, making it suitable for both freshwater and seawater applications.¹

Vicon HT^TM Breaker System. Vicon HT breaker system was specifically designed for Delta FracPac fluid. While conventional breakers are only effective at temperatures up to 170°F, this system was designed for use at temperatures above 150°F (Fig. 6).^{1, 2} The new breaker system exhibits an initial delay followed by a rapid break, allowing operators to maximize breaker loadings without changing the rheological properties of the fracturing fluids during the treatment. The system also provides adjustable break times, allowing it to be tailored to individual treatment needs.

Fig. 6—Comparison of a 25-lb/Mgal Delta FracPac fluid with and without the new breaker system at 190°F

Fluid Loss. Delta FracPac fluid provides fluid-loss control as effectively as conventional borate systems. In tests performed on 200-md berea cores at 140°F, a 25-lb/Mgal Delta FracPac fluid exhibited a spurt loss of 0.23 gal/ft² and a 0.0030-ft/min C_w value. The conventional, 35-lb/Mgal fluid exhibited a spurt loss of 0.63 gal/ft² and a 0.0035-ft/min C_w value.³

Conductivity. Long-term production is directly related to fracture conductivity which is dependent on the fracturing fluid used during the treatment. Excessive amounts of gel and other insoluble residues can significantly reduce fracture conductivity. Because Delta FracPac fluid places less gel in the formation, it also leaves less gel behind. When compared to conventional borate-crosslinked fracturing fluids, Delta FracPac fluid allows 30 to 40% more fracture conductivity to be retained.¹

Proppant Transport. Tests have shown that both conventional borate-crosslinked fracturing fluids and Delta FracPac fracturing fluids exhibit good dynamic proppant-transport capabilities. However, Delta FracPac fluid exhibits near-perfect laminar flow profiles, while conventional borate fluids create distinct layers of proppant-laden fluid travelling at different velocities and having different apparent viscosities. In addition, Delta FracPac fluid distributes proppant homogeneously throughout the height of the fracture simulator while the conventional fluids show signs of stratification. The conventional fluid also deposits high concentrations of proppant at the bottom of the simulator.^{1, 2}

Skin Values. Skin values indicate the success level of a stimulation treatment. Positive skin values indicate formation damage or impaired productivity. Delta FracPac fluid typically produces low skin values and often produces negative skins, indicating a successful stimulation treatment.¹ Fig. 7 compares the skin values produced with conventional fracturing fluids and Delta FracPac fluid.

Fig. 7—Fracpack results comparing conventional borate fracturing fluids with Delta FracPac. Experience shows that a –2 skin (average skin achieved after a number of Delta FracPac treatments) often can provide significantly better production than the average +2 skin achieved with conventional fluid systems.

Control. In addition to providing adjustable break times, Delta FracPac fluid allows gel to be mixed on-the-fly. Consequently, each treatment can be tailored to meet the needs of the operator. The system’s on-the-fly capabilities enable instantaneous gel loading and base-gel viscosity changes with no time lapse.

Case Histories

In addition to the Stim Star case histories presented at the beginning of this article, Delta FracPac service has been successful in several other GOM fracturing treatments.

Case 1. An operator needed maximum stimulation and effective sand control in a highly laminated, unconsolidated formation. Halliburton recommended a 25-lb Delta FracPac treatment consisting of 13,200 gal of fluid and 60,000 lb of proppant. The treatment was placed successfully at a rate of 15 bbl/min and the well was brought on-line at 15 MMcf/D. Previous gravel-pack treatments had only produced 6 MMcf/D. The total economic value of the Delta FracPac treatment was $18,000 per day.

Case 2 An operator wanted to maximize production from a 10-ft oil-bearing sand with a 40° deviation at the perforations. The bottomhole temperature (BHT) of this well was 172°F. Halliburton recommended a 25-lb Delta FracPac treatment. Using the Stim Star, 8,000 gal of fluid carrying 32,000 lb of proppant was mixed with seawater and pumped on-the-fly. Bottomhole gauge data indicated a 1,000-psi increase in net pressure for the tip screenout. After being shut in for approximately 8 weeks, the well began producing at 848 BOPD and 1.6 MMscf/D. These production rates exceeded the operator’s predictions and resulted in an incremental economic value of $215,000 (based on a production rate of 200 BOPD for 60 days).

Industry experience has shown that wells treated with fracpacks requiring extended shut-in times often have to be jetted before they will begin producing. These wells also tend to require longer cleanup times. This completion, however, produced naturally and cleaned up in a few days. Based on a 50% probability that the Delta FracPac treatment eliminated the need for jetting, the treatment saved the operator $15,000. In addition, the combination of lower gel costs, reduced loading time, and eliminated cleaning charges saved the operator another $10,000. Overall, this treatment provided the operator with an economic value of $240,000.

Case 3. An operator needed to complete a 500-md oil-bearing sand with a 24-ft interval and a 70° deviation at the perforations. Halliburton recommended a 20-lb Delta FracPac fluid with an enzyme breaker. After the Stim Star pumped the sand-laden fracturing fluid, bottomhole gauge data indicated a 700-psi increase in net pressure for the tip screenout. Based on previous fracpacks performed in this area, the operator expected the well to produce 650 to 700 BOPD. However, after the Delta FracPac treatment, the well produced 1,200 BOPD and exhibited a skin of -1.7. Based on an anticipated production rate of 600 BOPD for 90 days of initial production, the total economic value of the treatment was over $1 million.

Case 4. A deepwater operator needed high production rates and low drawdown rates from a highly permeable, poorly consolidated sand with a 270-ft interval. At a depth of nearly 18,000 ft, the reservoir pressure was higher than 9,600 psi. Halliburton performed a single-stage Delta FracPac treatment. Cased-hole production logging and radioactive tracers confirmed that the entire treated interval was producing uniformly. The well is currently producing over 18,000 BOPD and 15 MMscf/D.

References

1. Ali, Syed A., et al.: “Offshore Frac Packs Benefit from Seawater-Based Borate Fluid” Oil & Gas J. (Sept. 1998) 49-62.

2. Powell, R.J., et al.: “Gulf of Mexico Frac-and- Pack Treatments Using a New Fracturing Fluid System,” paper SPE 39897 presented at the 1998 International Petroleum Conference and Exhibition of Mexico, Venezuela, March 3-5.

3. Terracina, J.M., Yaritz, J.G., Powell, R.J., McCabe, M.A., Slabaugh, B.F., and McKeon, M.J.: “Low Gel Loading Increases Well Production in Eastern U.S.” paper SPE 51070 presented at the 1998 SPE Eastern Regional Conference and Exhibition, Pittsburgh, PA, Nov. 9-10.