In a 25,000 ft (7,625 m) well, for example, using WFF can result in an over 18% reduction in surface pressure. (Images courtesy of Halliburton)

Weighted fracturing fluid harnesses the power of gravity to reduce the amount of surface treating pressure required to achieve adequate fracturing pressure and treatment pump rates without exceeding the safety limits of surface equipment, tubulars, and high-pressure manifolds. Conventional completion methods for these deepwater wells, such as gravel packing, statistically give lower production rates in similar reservoirs.

Properly weighted frac fluid is especially valuable in extremely deep wells in areas of the world where piping and flexible treatment lines impose pressure limitations. Limits on available land-based equipment are about 20,000 psi; the offshore equipment limitation is about 15,000 psi.

How it works

Equation 1 and the example calculation below show how the weighted frac fluid (WFF) adds to fracturing pressure while reducing surface treating pressure in an offshore well. Surface treating pressure (STP) equals the sum of fracturing pressure (FRP) plus tubing friction pressure (TFP) minus hydrostatic pressure (HP). In the example, the increase in HP reduces the STP by 3,065 psi, or enough to reduce STP below the 15,000-psi limitation on offshore surface equipment, manifolds, and tubulars (Figure 1).

STP = FRP + TFP – HP (1)

• HP: Conventional psi: 11,310;
Weighted psi: 14,375
• TFP: Conventional psi: 5,485;
Weighted psi: 5,485
• FP: Conventional psi: 22,500;
Weighted psi: 22,500
• STP:Conventional psi: 16,675;
Weighted psi: 13,610

WFF enables fracpack and hydraulic stimulation of ultra-deep reservoirs. The fluid used is a high-density fracturing system using sodium bromide brine with or without propylene glycol as the base fluid. The WFF is a borate cross-linked fluid using hydroxypropyl guar (HPG) gelling agent. The fluid can be used in wells with bottomhole static temperatures (BHST) of 80 to 325°F (27 to 163°C). Typical specific gravity (sg) for an aqueous frac fluid is 1.00 to 1.04; WFF has 1.30 sg to 1.38 sg.

Equation 1 shows that an increase in hydrostatic pressure results in a reduction in surface pressure. This remains true if any corresponding increases in bottomhole treating pressure (BHTP) and friction pressure remain below the hydrostatic increase. If substantial reductions in surface pressure can be achieved, fracpack treatments remain a safe and viable option in deepwater and ultra-deepwater environments.

In operational areas prone to producing gas hydrates (crystalline solids that consist of gas molecules surrounded by cages of water molecules), WFF can be formulated to inhibit the formation of the gas hydrates.

The weighted frac fluid is characterized by a base density of 11.5 lb/gal as compared to the standard base density of 8.7 lb/gal for standard frac fluid. The WFF was composed of HPG gel, using the same additives as the standard density frac fluid. It underwent extensive fluid testing, compatibility testing, and regained permeability testing. The fluid can be discharged into the ocean and can be stored for long periods of time with no adverse effects.

Discussion

The surface treating pressures were estimated using Equation 1. For the frac fluid, the friction was estimated using a multiplier of 1 in the friction mode. For the weighted frac fluid, a multiplier of 1.2 was used in the friction model. If a job was bullheaded down, the friction was estimated at the bullheading rate until the rate was increased to start injecting the pad stage into the formation. Once the rate increased due to the start of injection of the pad stage, the friction was estimated at the injection rate for the remainder of the stages. The STP was then estimated and compared with actual data from the job as soon as pumping started for the frac job.

If a job was spotted down, the friction was estimated at the injection rate for the pad and sand-laden fluid (SLF) stages. The STP was then calculated and compared to the actual job data after the tool was shifted to the weight-down circulate position, and injection of the cross-linked gel began.

The STP was estimated using a volume weighted average proppant concentration. The first step was to calculate a maximum average wellbore concentration.

The largest proppant concentration stage was calculated first, and the next largest concentration stage was calculated next, and so on until the well bore was full of slurry or the whole frac job was in the well bore. Once the MAPC was calculated, an average was taken over five steps to give five average SLF concentrations with which to estimate friction. This value combined with the pad and flush stages made up the points on the estimated surface treating pressure graphs.

Case Histories

In a September, 2006 press release, Chevron said it had completed a record-setting production test on the Jack No. 2 well on Walker Ridge Block 758 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) below the sea floor, breaking Chevron’s 2004 Tahiti well-test record as the deepest successful well test in the Gulf of Mexico. Jack No. 2 was drilled to a total depth of 28,175 ft (8,593 m). The test was designed to evaluate a portion of the reservoir’s total pay interval. During the test, the well sustained a flow rate of more than 6,000 b/d of oil with the test representing approximately 40% of the total net pay measured in the Jack No. 2 well.

WFF was a critical technology in the completion of this new discovery well. This operation would not have been possible without the use of WFF.

Authors’ Note: This article is a summary of SPE 112531, “Weighted Frac Fluids for Lower Surface Pressures,” presented at the 2008 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, La., 13-15 March.