Horizontal Well Fracture Stimulation Experience in Prudhoe Bay
Authors: Sanders G.S. , Weng X. , Ferguson K.R. 
Published: December 2007

Abstract
Horizontal wells can be some of the most difficult completions to fracture stimulate. Several factors including propensity for multiple fracs, unpredictable fracture geometry, and well azimuth/deviation effects contribute to uncertainties in horizontal well fracture design. Radioactive tracers in a datafrac and subsequent propped fracture treatment has helped understand some of these fracturing challenges. The experience in Prudhoe Bay field demonstrates that successful fracture treatments of horizontal wellbores, even wells with over 1000 feet of perforations, can be achieved. Seven horizontal wells have been fracture stimulated resulting in as much as a ten fold increase in production rate. Most of these wells were producing at low rates due to formation damage or low reservoir quality and were under-performers relative to expectations.

Introduction
Most new wells and sidetracks drilled in the gravity drainage area of the Eastern Operating Area (EOA) of the Prudhoe Bay Field are horizontal completions with cemented and perforated liners averaging over 1000 feet horizontal section. Placement of the horizontal wellbores are governed by geologic features, such as faults, high permeability streaks, shale barriers, proximity to gas, etc. To minimize gas production, the horizontal wells have targeted the base of the Sadlerochit sandstone, the primary producing zone of the Prudhoe Bay Unit.
In most cases, there is no stimulation required to produce these wells at an acceptable rate. Average permeabilities of this sandstone formation are 50-100 md in the bottom 50 TVD. However, approximately 10% of the wells drilled have low productivity and require stimulation. Reasons for low productivity include drilling/completion damage, cement damage, poor rock quality, isolated zones, etc.
Both acid and fracture stimulations been performed on horizontal wells in the EOA. Fracture stimulations have proven to be the most successful. The main challenge of the fracturing program on horizontal wellbores was the issue of proppant placement and fracture containment prediction. It was recognized that horizontal wellbores with up to 1000 feet of perforations and varying azimuths could be very difficult to fracture because of the aforementioned reasons.
Most of the previous fracture stimulations completed in the EOA have been on wellbores less than 60 deviation. In fact, prior to 1996 only one fracture stimulation had been attempted on any of the approximately 80 horizontal wellbores. A total of seven fractures have been performed on horizontal completions in the EOA at this time.

Case Histories
Two case histories are presented here. The first case history (Well A) was the second fracture stimulation attempted on a horizontal wellbore in the EOA, but the first on a cemented and perforated liner (first attempt was on a slotted liner). The second case history (Well B) highlights the use of radioactive tracers and modeling to help interpret fracture geometry and number of fractures created during a treatment.
Well A. This well is an inverted horizontal well drilled in 9/94 into Zone 1 at the base of the Ivishak formation. A low solids polymer based mud system was used during drilling with no lost circulation. A 7" liner was run and cemented with acid resistive cement. Additional water was added to the cement thinning it out, possibly contributing to formation damage. A total of 665 feet of perfs (Fig. 1) split into an upper and lower set were shot at 4 spf, 90 phasing.
Initial production rate was 500 bopd and slowly increased to 700 bopd during the first 7 months, but still lagged offset horizontal producers completed in the same zone. Due to low flow rate and 4–1/2" tubing, this well had a paraffin problem which required periodic hot oil washes. Stimulation options were necessary to increase rate and reduce the number of hot oil treatments.
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