Wellbore stability issues had plagued early attempts by Southwestern Energy Company subsidiary SEECO Inc. to drill and complete horizontal wells in the Fayetteville Shale in Arkansas’ Arkoma Basin. Unstable zones, particularly the Morrow Shale, had created operational problems including repeated instances of stuck casing and liners that had cost the operator significant time and money. Stabilizing these shale sections was critical to controlling drilling time and cost.

Development activity to date has been primarily focused in Cleburne, Conway, Faulkner, Van

Figure 1. Flow of 0.22 mL/hr into the shale from the fluid is anomalous. Slight loss of hardness throughout core may be due to mud/shale activity imbalance. Wellbore stability is comparable to that observed in Test 3.

Buren and White counties due to shale thickness. Of these, the westernmost counties of Conway, Faulkner and Van Buren typically are drilled with water-based fluids. Farther east, in White and Cleburne, oil-based systems are common.

As of November 2006, the company estimates reservoir drainage to be about 80 acres per horizontal well, with gross production of about 1.4 Bcf per well. Based on this data, the company projects a potential for some 8,000 horizontal wells to be drilled for an estimated ultimate recovery of 11.2 Tcf of natural gas.

Fluid system

Newpark Drilling Fluids recommended a FlexDrill/FlexFirm drilling fluids system specifically formulated for use in this area. This system combines the company’s proprietary membrane-building polyol technology (to insulate the well bore from destabilizing effects of osmotic fluid invasion from the drilling fluid) with patented new shale stabilization enhancement achieved through new silicate technology.

Figure 2. Flow of 0.11 mL/hr into the shale from the fluid is expected. The significant loss of hardness at the wellbore indicates poor wellbore stability. This fluid provided the least wellbore stability of the three tested.

Results improved significantly when the system was employed in some 50 field applications. Tests were then undertaken to confirm the optimized fluid formulation to address the specific challenges of the Morrow Shale. Shale stability tests were conducted on Morrow Shale core samples with the recommended formulation and two principal fluid system alternatives commonly used in the area.

Downhole simulation testing

Newpark’s Downhole Simulation Cell (DSC) was used for testing drilling fluid performance, with particular focus upon improving wellbore stability with controlled activity fluids. The operator provided cores of the Morrow Shale for DSC testing.

Using the DSC, individual cores were returned to their in situ downhole environment of stress, temperature and pressure, and drilled with various fluid formulations. These tests demonstrated fluid performance and subsequent effect upon shale stability achieved by three fluid systems — diesel oil-based fluid, freshwater gel chemical fluid and the recommended proprietary water-based system.

The recommended water-based formulation featured a polyol-based shale stabilizing agent, and 2.0 ppb of the anhydrous potassium silicate product to provide additional wellbore stabilization. This environmentally friendly formulation compared favorably to the competing gel/chemical formulation, which contained asphalt blend oil (ABO), and to the diesel oil-based fluid, whose components presented expensive environmental drawbacks.

Results confirmed the shale stabilization capabilities of the proprietary silicate/polyol system

Figure 3. No flow between shale and fluid indicates the mud effectively sealed the wellbore surface. No significant alteration of exchangeable bases or interstitial ions is seen in the shale. The shale retained its hardness and showed least effect from drilling fluid. Wellbore stability is comparable to the diesel oil fluid of Test 1.

as superior to the conventional gel/chemical fluid system. The shale core drilled with the proprietary system appeared unaltered by exposure to the fluid under drilling conditions. No practical fluid transfer was observed between the fluid and the core. The exchangeable ions and interstitial ions showed minimal change across the cores and were similar to initial (pre-test) values. Core hardness was also unchanged by the DSC drilling process.

By contrast, both the oil-based fluid and the generic gel/chemical fluid altered the core via fluid transfer from drilling fluid to the shale, though in the case of the oil-based mud a mud/shale activity imbalance was the suspected culprit. A loss of core hardness, or strength, was noted with the gel/chemical fluid. Wellbore stability was judged as “poor” with the generic gel/chemical fluid, which “provided the least wellbore stability of the three (samples) tested,” the test report noted.

The fluids company is now conducting similar formulation testing with controlled activity oil-based fluids. Those tests target achieving enhanced performance by altering oil-mud salinity content, as well as testing the company’s polyol activity-control agent in place of calcium chloride. The polyol has achieved activity control with performance benefits in other regions.

Like other operators, Southwestern Energy has had little success thus far with water-based systems in farther eastern White and Cleburne counties. There, the thicker Morrow shale, which results in extended horizontal wellbore exposure in terms of both footage and time, has required oil-based fluids. But even with oil-based fluids, the company has found that improved and patient drilling practices aimed at dealing with the Morrow’s highly-fractured structure are equally vital to minimize costly fracture-related hole problems.

Typical well program

The operator’s typical Fayetteville Shale well calls for a spudder rig to drill a 12.45-in. hole to about 550 ft (168 m) and set 95¼8-in. casing, then drill out 87¼8-in. vertical hole to about 3,000 ft (915 m). This upper hole section is typically drilled with air/mist fluid, and the hole is displaced with 9.5 ppg fluid (reconditioned fluid is used) before a larger rig is moved in.
The vertical 8.5-in. wellbore is drilled to kickoff point in the Morrow at around 3,200 ft. Angle is then built to horizontal. During the field development program, the operator’s drilling engineers have experimented with various rates of build (from 10-14°/100 ft or 30 m) to ensure a stable wellbore and a smooth build section. If necessary either for wellbore protection or to accommodate completion geometry, 7-in. casing is run through this section.

Finally, a +/-2000 ft (610 m) horizontal section in the Fayetteville is drilled and 5 1/2-in. production casing is set. Fluid density at total depth is generally <10 ppg.
The Morrow is an unpredictable formation for building angle due to stratigraphy and varying compressive strengths. The Basal Hale section just above it — an abrasive sandstone — presents operational challenges regarding lubricity and hole cleaning.

Mud program

Drilling fluid goals focus on shale inhibition for a stable well bore and adequate hole cleaning in all sections to eliminate the 7-in. casing and achieve programmed lateral depth. Special attention is given to low shear rate rheology to ensure proper hole cleaning, with 6 rpm viscometer readings of 7-9. API fluid loss is maintained below 4cc from kick-off point to total depth. The system is dispersed with additions of a chrome-free organic thinner, along with a humalite fluid conditioner. A turbulent flow regime is maintained to enhance hole cleaning once angle exceeds 35°.

The fluid is treated with LST-MD, a proprietary complex polyol shale stabilizer, and the potassium silicate shale stabilizer in low concentrations, with daily additions to maintain appropriate levels. A proprietary field test method was developed by the fluids company to ensure that recommended concentration is maintained. Prior to trips or running casing, a lubricity pill containing proprietary polyol product, graphite and glass or polymer beads is spotted in the open hole.

Operational improvements

Since incorporating this fluid formulation, the operator has seen improved well-to-well results. Improved wellbore conditions have resulted in elimination of 7-in. casing, extended lateral footage and a reduction in total days per well from 40 to as low as 81 /4 days. Average per-well drilling fluid cost has been halved. The addition of drilling fluid lubricity agents has also improved drilling penetration rates while making casing runs more efficient.

The value of proprietary shale stabilization products was confirmed when concentrations were varied to gauge cost versus operational benefits. Lower concentrations resulted in a less stable wellbore; returning to original recommended concentrations improved fluid performance in terms of wellbore stability and penetration rates. In critical situations with long horizontal sections, concentrations have been increased to ensure maximum performance.

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