A uniquely engineered invert emulsion reservoir drill-in fluid is credited with helping increase production rates as high as three-fold in the Alpine field of the Alaskan North Slope.

Earlier wells drilled on the massive structure employed water-base drill-in fluids. However, these systems reacted negatively to the distinctive characteristics of the Alpine reservoir. The formations intrinsic to Alpine are unique in that the rocks are oil-wet whereas most oil-bearing rocks are water-wet. Consequently, the increased water saturation from aqueous reservoir drill-in fluids obstructed pore throats in the reservoir, thereby reducing the available hydrocarbon flow area and subsequently lowering production rates.

Replacing the aqueous systems with the newly developed low toxicity mineral oil-base fluid essentially cleared the way for higher production.

The new mineral oil-base system

While invert-emulsion drilling fluids inherently produce minimal formation damage, the high solids content of conventional systems often impairs the completion, thus restricting production. The new mineral oil-base fluid was designed to offer the superior drilling characteristics of conventional invert emulsion fluids, while selecting the proper type and size bridging particles so as not to restrict production. In conventional reservoir drill-in fluids, solids content typically is not engineered with consideration given to the type or size of the bridging particles.

One of the benefits of this system is that it is able to sustain a 50/50 oil-brine ratio. Unlike conventional reservoir drill-in fluids, the density of the internal phase of the new system is maximized and may comprise any type of clear brine fluid, such as calcium chloride, calcium bromide, sodium bromide, potassium formate and cesium formate, among others. The system incorporates properly sized solids for bridging the formation. Yet, even with minimal solids the system still can be formulated with densities of 7.0 lb/gal to 14.0 lb/gal.

Furthermore, the versatile system can be used either as a reservoir drill-in or completion fluid and also has been employed as a displacement or perforating pill. The system has been used successfully in both cased and openhole completions where the comparatively higher drill performance characteristics of oil-base drilling fluids are required. Further, as a cased hole perforation pill, it has been shown to minimize the threat of solids plugging the perforation tunnels, while preventing losses to the reservoir. In openhole completions, the new system is effective as a low-solids fluid-loss control pill, which is designed to remain in the productive target prior to running the completion assembly. It also can be used as a temporary abandonment fluid to minimize the risk of solids settling prior to the initiation of production.

Completing the new mineral oil-base system is a proprietary software package that ensures optimum bridging with the proper amount and size of solids. The particle size distribution software was developed to remove trial and error in the selection of bridging particles. Selecting the optimum blend of particles effectively seals the formation, thus minimizing damage and increasing production. For the Alpine project, much focus was placed on engineering a match between the particle size distribution of acid-soluble bridging material with the porosity and permeability characteristics of the reservoir.

The Alpine field

With an estimated 430 million bbl of recoverable reserves, the Alpine field remains the third largest onshore discovery in North America. Located in the Colville River area, 34 miles west of the Kuparuk River field and near the border of the National Petroleum Reserve, Alaska, Alpine also is the western-most producing oil field on the North Slope. The 40,000-acre field was developed on just 97 acres, or two-tenths of 1% of the field area.

Alpine was declared commercial in 1996 and initiated production in 2000, currently producing at a rate of about 100,000 b/d. An expansion project presently underway at the complex is planned to boost production to 140,000 b/d by mid-2005. The Doyon Rig 19 is expected to drill more than 100 horizontal wells on the two Alpine drill sites.

The complex is being developed exclusively with horizontal well technology and employs enhanced oil recovery (EOR). The field's unique design and the use of EOR will help extract more oil from the reservoir.
Alpine is essentially a zero-discharge facility, meaning all cuttings and other generated drilling wastes are either reused, recycled or properly disposed. Unique to the facility is a three-story drill cuttings Grind and Injection System (GIS) that since its commissioning has re-injected more than one million bbl of slurry with a remarkable record of near zero downtime.

Although ice roads are constructed in the winter to allow for the transportation of equipment and drilling supplies to the site, there is no permanent road to the field. These roads minimize environmental impact, as they melt in the spring, leaving no footprint on the tundra. Small aircraft also provide service to the field.

Increasing production rates

At 15% to 20%, the water saturation of the fine-grained sandstone reservoir intrinsic to the Alpine field is low. Similar reservoirs have higher water saturations, typically approaching 25%. Owing to its comparatively lower saturation rate, the Alpine reservoir tends to absorb an unacceptable volume of water, which is particularly evident when using an aqueous-base drilling fluid. Consequently, the Alpine Subsurface Development team recommended producing wells be drilled with an oil-based drilling fluid to help minimize the formation damage caused by this water-imbibition phenomenon.

In a sensitive ecosystem like Alpine, the selection of an invert emulsion drilling fluids raises a host of HSE concerns. However, following a detailed HSE review by the operator, rig contractor and drilling fluid provider, the decision was made to use mineral oil (LVT-200) instead of diesel as the base fluid. Though mineral oil is considerably more expensive than diesel, it is much more environmentally acceptable from an HSE perspective. Compared to its diesel counterpart, mineral oil has a much higher flash point with a lower aromatic capacity, which is critical when used within an enclosed arctic drill rig. Further, the mineral base oil is more compatible for fluid handling and transfers.

The production results realized by using the mineral oil-base system have been very positive, with rates two to three times higher than similar wells drilled with the water based fluid systems. Though this system has increased fluid costs the increased production rates have more than offset the added expenditure.
Furthermore, drilling performance has improved dramatically, further reducing overall project costs. North Slope drilling efficiency or key performance indicator (KPI) is measured by how long it takes to drill a well to total depth (TD) and then normalized to 10,000 ft (3,050 m) (days/10,000 ft). Alpine wells are drilled with three individual hole sections that include horizontal laterals in pay as long as 7,000 ft (2,135 m). Early Alpine wells had required as long as 20 days to drill to TD. Recent Alpine wells are being drilled to nearly 20,000 ft (6,100 m) measured depth with KPIs as fast as 8 days/10,000 ft.

Elsewhere on the North Slope, the new mineral oil-based system was used to drill the first quad-lateral in Alaska, establishing state records for longest liner and most footage drilled. The laterals ranged from 3,843 ft to 7,249 ft (1,172 m to 2,210 m) in length with a cumulative footage of 27,743 ft (8,461 m). Total footage for the well was 34,798 ft (10,613 m).

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