One of the first questions raised in any new play being developed is how many wells, and exactly what type of wells, will best produce the reservoir with the highest efficiency and the least cost.

To answer that question for operators in the Bakken formation in the Williston Basin in Montana, IHS Inc. undertook a study of individual wellbores in the play.

The Bakken has experienced an explosion of activity since 2000, due to the effective use of stimulation and horizontal-drilling technology and operators’ desire to optimize operations and reduce costs. Current IHS data reveal that production in the Elm Coulee Field area of the Bakken has increased to rates exceeding 1.5 million barrels of oil per month, up from some 10,000 barrels per month in 2000.

In the past seven years, more than 480 wells, involving 730 laterals, have been completed and were reporting production in March 2007.

The cumulative number of horizontal Bakken wells drilled in the Elm Coulee area is now more than 500 and includes more than 800 laterals.

MontanaMeanwhile, horizontal-well completions are now yielding economically attractive initial production (IP) rates averaging 425 barrels of oil per day (although some IPs have been reported prior to fracture stimulation). Recoverable reserves are averaging more than 500,000 barrels of oil per well, according to “The Middle Bakken Member (Lower Missis­sippian/Upper Devonian), Richland County, Montana." The paper was presented at the American Association of Petroleum Geologists’ Rocky Mountain Section meeting in Billings, Montana.

Various horizontal-well configurations have been drilled with up to seven laterals being completed from a single wellbore. Combining multilaterals with new completion technology has resulted in highly productive wells, making the Bakken formation one of the most active plays in the U.S.

The area included in the IHS analysis is the Elm Coulee area in Richland County, Montana, on the western side of the Williston Basin. The reservoir is a stratigraphic trap developed in the Middle Bakken member, with up to 14 feet of reservoir.

It bears up to 12% porosity, has a permeability of less than 0.2 milliDarcy and oil saturations in the 75% range. The reservoir is also slightly overpressured. Local variations in reservoir properties and fracture development have been a major factor in well productivity throughout the area.

Completion techniques

Operators fractured their early Bakken vertical wells using standard techniques with water- or hydrocarbon-based fluids and sand. IP rates were often encouraging. However, the vertical wells exhibited high-initial-decline rates and their low-matrix permeability provided long-term, but uneconomic, production rates.

Beginning in 2000, horizontal-well completion methods used cemented lateral liners and limited-entry perforation techniques in an attempt to control fracturing. Efforts were made to control vertical-fracture growth into the overlying Lodgepole formation or the underlying Three Forks reservoir seals. Surveys indicated the lateral toe was preferentially being treated using this technique.

Operators have since modified their completion techniques, including using non-cemented and preperforated liners, longer laterals, cleaner fracturing fluids, staged treatments with diverters, aggressive gel breakers and increased proppant volumes. These modifications have significantly improved well productivity and reduced costs.

Operators have since experimented with the configuration of the laterals. Different multilateral configurations have been drilled to find the ideal number of laterals to achieve optimum productivity, improve recovery from noncore areas and reduce costs. What is the wellbore configuration that should be drilled to yield the optimum economic return in this formation? The answer to this is sought for operators and investors in analyzing the performance of the 440 horizontal wells included in this study.

The results

To evaluate the individual wellbore configurations, wells were grouped by the total number of laterals drilled from each vertical wellbore. Production history was summarized for each type of wellbore configuration and a normalized average well was created for each configuration.

Subsequently, production forecasts were made based on each normalized average production history, with consideration given to the long-term performance of vertical wells drilled in the 1980s and 1990s. Economics were developed for each normalized average well based on specific economic parameters.

For this evaluation, some basic assumptions were made. It was assumed that completion technology has progressed equally across all configurations, the play is a homogeneous reservoir with no variation between wells, and lateral orientation is identical for all wells.

IHS made economic evaluations of each typical well made using PowerTools, a decline-curve and economics-analysis software tool.

Based on the economic indicator of 10%-discounted cash flow and the assumptions previously stated, the study shows that single laterals or dual laterals are confirmed to be the most economically effective in the Bakken formation. Given the assumptions, the most cost-effective drilling technique would be when, for example, two vertical wells are drilled with two laterals from each, as opposed to one vertical well with four laterals. This is barring any physical restrictions such as a lake or a road, which would require multiple laterals to effectively produce the reservoir.

Factors such as surface-access limitations, an anticipated lower-quality reservoir and company reserve volumes were not considered in this evaluation.

When deciding the ultimate number of laterals to drill from a single vertical well, additional investigation should focus on the effect of a given geographical location, the effect of lateral orientation, and the effect of fracturing rates and pressures. M

Brian Wright is senior geoscience product advisor for IHS Inc., Houston.

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