Creativity in the Clearwater

Heavy oil in the Clearwater Formation was first targeted for development using vertical drilling as early as 1984. Low permeability combined with high oil viscosity lead to less than desirable results. With the advent of hydraulically fractured horizontal wells, several operators saw new opportunities to utilize this technology to increase permeability and boost production. These early attempts were largely unsuccessful, which we now know was due to the adverse effects of drilling and completion fluids on the wettability and clay content of the Clearwater formation.

Beginning in 2014, Spur Petroleum began using unstimulated open-hole multilateral horizontal wells at Whitford and Jarvie to maximize reservoir contact and economically produce the heavier crude oil. With their success and knowledge, they quickly began buying up land across Alberta with a heavy focus in the Marten Hills and Nipisi regions. Deltastream Energy, Cenovus Energy, Canadian Natural Resources Ltd. (CNRL) along with Highwood Oil Corp also locked up key land in the main Marten Hills and Nipisi fairways.

Development throughout the Clearwater has increased rapidly since and as of March 2020, a total of 307 multilateral wells were producing at a combined rate of just over 31,000 bopd. Across the province operators have been targeting multiple Clearwater intervals (A-E) including shoreface and channel sands, across over 15 different fields. To date nearly 75 percent of production is currently from the Marten Hills field.

Figure 1: Total Clearwater Oil Production by Field

Multilateral drilling has been applied all over the world starting in Russia and the Middle East and pioneered in Alberta by Baytex Energy and CNRL at their Seal development in the Peace River oil sands. Development of the Clearwater using multilateral wells is heading into its 5th year. In these mere 5 years, 330 multi-leg wells have been drilled which is equivalent to just over 1,900 single leg horizontals with 2,856 km of open hole reservoir exposure. Enough hole in the ground to get El Chapo from Juarez to Edmonton.

Without the need for hydraulic fracturing in the Clearwater, completions engineers have stepped aside allowing drilling engineers to fill the void of our innate desire to tinker. The Clearwater is a drilling engineers dream sand box with countless unique and interesting ways to drill a multi-leg well. From the overall leg count and leg configurations down to minor nuances of how each additional leg branches off from one another and the various junction designs. A balancing act of maximizing reservoir exposure, maintaining drilling efficiencies and minimizing costs, while keeping in mind the impact on rates and recoveries.

Horizontal lengths have remained fairly constant at 1-mile long laterals, while operators experiment with leg count and inter-well spacing. So far the leg count has varied from 2 to 9 legs per well with inter-leg spacings ranging from 20 to 75 meters. Currently 6 legs at 50 m spacing is the most popular combination. A normalized production plot comparing the various leg and spacing combinations within the Marten Hills field is shown below. The plot shows that currently 4 leg wells spaced at 50 m and the 8 leg wells at 20 m are the top performers. It should be noted however that geology is still the number one driver of productivity and can change very quickly across the play making concrete conclusions on optimal well design challenging.

Figure 2: Oil Rate per 100m of Open Hole versus Cumulative Oil Recovered

Almost all multilateral wells to date in the Clearwater have been somewhat conventional, with one or two main laterals in which the additional legs branch out and run in parallel to each other. Depending on the number of legs and number of wells on the pad, various sidetracking or junction configurations have been executed. A few of the various configurations are shown below in Figure 3.

Figure 3: Junction Designs in Clearwater Multi-leg Wells

While the differences are subtle, the impact of junction design on production can be related to fluid inflow and gas breakout. With the highest draw down at the heel of the well combined with vast amount of open hole there will be a large amount of fluid flow into the heel area. This turbulent flow and higher drawdown will promote more gas breakout in the heel leading to an increase in foamy oil which can reduce pump efficiencies.  A larger pressure drop could also amplify water or gas coning depending on well placement within the zone. Junction design also needs to consider wellbore stability and potential for open hole collapse in these areas. Downhole equipment or future re-entry needs could also play a factor.

One unique multilateral design being tested by operators is a fishbone or herringbone style well as shown in the figure 4 below. The unique well designs mimic burrowing tactics used by ancient organism in resource deprived environments as interestingly described in a 2019 Geo-convention report by Raychaudhuri, Young, MacEachern and Gingras, 2019¹. The design of these wells complicates things further as tweaking of branch length, branch number, and branch angle can all influence productivity. The benefits of such wells over the conventional design will come down to drilling efficiencies and costs savings. Other benefits include more precise leg placement with the ability to adjust future branches based on previous branches drilling data, as well as less time in hole per branch reducing formation damage. To simulate the same areal drainage area as a mile long 6-leg well at 50 m spacing, Spur has drilled a fishbone well with 21 lateral branches at 50 m spacing with each branch approximately 375 m long. Crestwynd Exploration has spudded a similar style well in the Radway field with an end goal of 34 branches.

Figure 4: Fishbone Multilateral Well Designs

Another type of multilateral well recently drilled by Spur is shown in Figure 5 below, where the legs start from one main hole and then fan out in straight lines. This design eliminates the bend or curved portion of drilling the outer most legs and can be used to efficiently drain corner sections of interest lands.

Figure 5: Fan Multi-lateral Design

A good example of creativity is Cenovus Energy’s full field development plan which focuses on multi-well pad placement to maximize reservoir exposure and reduce spoilage across their acreage. Carefully choosing surface pad locations and overlapping heel placement as well as extending legs as far as possible into stranded areas.

Figure 6: Full Field Development Multi-lateral Design to Reduce Spoilage

In Marten Hills, the large pay thickness opens up the additional variable of vertical placement and the potential for multiple wellbores within the same vertical plane. One strategy is to drill separate wells one on top of the other. Spur is currently executing this across their lands with thicker pay and have even gone up to three separate wells on top of each other. Another method, pioneered by Deltastream Energy is the wine-rack configuration, where legs are drilled in an alternating offset pattern, one high and one low, repeating. Deltastream utilizes this method with 8 leg laterals with 5 to 7 m of vertical offset between the alternating legs and 20 m horizontal inter-leg spacing. This method helps capture the full vertical pay thickness from one well, while also mitigating any potential vertical permeability barriers.

With multiple separate exploitable stacked sands in some of the other Clearwater fields we could see the multi-lateral stacked development also being applied to target multiple horizons at once from a single surface hole. To better understand and evaluate these complex trajectories, GLJ models each laterals survey data in 3D space to determine exact well placement and assist in oil volumetric calculations and reserves estimates.

Figure 7: 3D Modeling of Leg Placement and Trajectory in Stacked Pay Areas

The individual well and full field design will become even more critical as the play transitions into secondary recovery methods, namely waterflooding. Areas of stacked development allows for injection of water into the lower most wells creating a bottom-up waterflood scenario. In the thinner pay intervals understanding how each well design will interact and respond in a line drive waterflood scheme will be the key.  

Drilling of multilateral wells seems only constrained by our imagination. With todays advanced drilling technology and directional expertise, there will no doubt be many new designs developed in an attempt to save capital and boost oil recovery.

References

1. Raychaudhuri, I., Young, M., MacEachern, J., Gingras, M. 2019. The Exploited: Ichnologic Analogs for Multi-Lateral Horizontal Oil Drilling Strategies in the Lower Cretaceous Grand Rapids and Clearwater Formations, Upper Mannville Group, Alberta, Canada.