In its deepwater Gulf of Mexico exploration area, Chevron has harnessed the force of gravity to reduce the amount of surface treating pressure (STP) required to pump frac-pack

Figure 1. In this example drawing, hydrostatic pressure adds to bottomhole treating pressure while reducing surface treating pressure. Calculations are given in Table 1. (Images courtesy of Halliburton)
treatments without exceeding the 15,000-psi pressure limits of offshore surface equipment. A special, single-salt, weighted frac fluid (SWF), designed for use where reservoir pressures exceed 20,000 psi, is being used to pump frac-packs. Table 1 and Figure 1 use a hypothetical example to illustrate the utility of the weighted frac fluid.

Keys to dealing with the great pressure forces involved are (1) knowing the shear history of the fluids and (2) managing the sheared fluids so that they retain proppant-transport properties adequate to place the treatment in the target payzone. An independent, third-party laboratory conducted extensive testing to support fluid
management necessary for project success.

A frac pack utilizing SWF was performed in the Chevron Jack #2 well at Walker Ridge in the Gulf of Mexico. The well was completed and tested in 7,000 ft (2,135 m) of water and more than 20,000 ft (6,100 m) under the seafloor. Total depth drilled was 28,175 ft (8,600 m). Many world records for test equipment pressure, depth and duration in deep water were set during the test. Perforating guns were fired at record depths and pressures. The test tree and other drillstem test tools helped Chevron conduct the deepest extended drillstem test in deepwater Gulf of Mexico history.

The operator Chevron has an interest of 50% in the Jack field. Statoil and Devon have interests of 25% each.

Using hydrostatic pressure
The effect of optimum hydrostatic pressure in the treating string makes it possible to enhance the productivity of ultradeep wells using fracture stimulation. Without fracture stimulation the economics of these projects would be significantly less attractive.
Conventional completion methods for these deepwater wells such as gravel packing statistically give lower production rates in similar reservoirs. The SWF service is especially valuable in wells of extreme total vertical depth (TVD) in areas of the world where piping and flexible treatment lines impose pressure limitations. Pressure limits on available land-based equipment are about 20,000 psi; the offshore equipment limitation is about 15,000 psi.

Figure 1 illustrates how the frac fluid used in the SWF service adds to fracturing pressure
Figure 2. These laboratory instruments were used to evaluate the SWF for viscosity, fluid loss and retained permeability. The fluids were prepared by mixing the components “on the fly” and pumping them through a tubing shear history simulator that simulated the tubing-wall shear rate and the time at shear for the fracturing treatment.
while reducing STP in an offshore well. STP equals the sum of bottomhole treating pressure (BHTP) plus tubing friction pressure (TFP) minus hydrostatic pressure (HP). In the example, the increase in HP reduces the STP by 3,065 psi (18.4%) or enough to reduce STP below the 15,000-psi pressure limitation on offshore surface equipment, manifolding and tubulars.
SWF service enables frac-pack and hydraulic stimulation of ultradeep reservoirs. The fluid used is a high-density fracturing system using sodium bromide brine. SWF frac fluid is a borate-crosslinked fluid using hydroxypropyl guar (HPG) gelling agent. The fluid may be used in wells with bottomhole static temperatures (BHST) of 80 to 325°F (26.6 to 162.7°C). The typical specific gravity for an aqueous frac fluid is 1.00 to 1.04; SWF fluid has a specific gravity of 1.30 to 1.38.

In operational areas prone to producing gas hydrates SWF fluid can be formulated to inhibit their formation.

SWF fluid is the first commercially available high-density fluid that can be used in hydraulic-fracture operations and/or frac-pack installations.

Testing the fluid
A 30-lb/Mgal SWF fracturing fluid provided by the service company was evaluated for viscosity, fluid loss and retained permeability. The fluid was dynamically mixed.
Figure 3. Single-salt, weighted fluid viscosity vs. time at 100 sec-1, as measured on the Fann-50 viscometer.
The test conditions simulated fracturing conditions for the specific frac-pack pumping schedules and workstring configurations. Figure 2 illustrates the laboratory instruments that were used for the tests. The fluids were prepared by mixing the components “on the fly” and pumping them through a tubing shear-history simulator that simulated the tubing-wall shear rate and the time at shear for the fracturing treatment. A Fann-50 viscometer was dynamically loaded with fluid from the end of the tubing to determine the viscous properties of the fluids. The fluid then flowed through three slot-flow dynamic fluid-loss cells containing representative formation core plugs obtained from whole cores.

The cores were saturated in synthetic formation brine at 250°F (121°C) and arranged in order from lowest to highest permeability. The SWF was pumped across the cores for 100 minutes with 500-psi differential pressure to obtain the fluid loss vs. time data. The cores were shut in at temperature for about 16 hours; then flowback with formation brine in the production direction was begun to determine the retained permeability.

Test procedures used are listed below:
1. A standard rheology test was run on Fann-50 with R1, B5.
2. A sequence was run using API.SEQ.
3. A shear history of 633/sec was taken for 14 minutes.
4. The 30-lb/Mgal fluid was mixed in 11.5-lb/gal NaBr brine.
5. After hydration, the base gel pH was adjusted.
6. Fluid also contained breakers consisting of 20 gal/Mgal oxidizing breaker and 1.0 gal/Mgal breaker activator.
7. Fluid was crosslinked with borate crosslinker.

The SWF had the linear gel pre-hydrated with all the additives including the breakers. The crosslinker was metered into the linear gel during pumping. Viscosity measurements were made on Fann-50 and Chandler Low Shear viscometers. Frac-shear results are presented in Figure 3.

The use of properly prepared weighted fracturing fluids can extend operator capability to pump frac-pack treatments without exceeding the pressure limits of offshore surface equipment. Keys to meeting the challenges presented by the great pressure forces concerned are learning the shear history of the fluid and retaining the proppant-transport properties in the sheared fluids.