Redesigning stimulation, lateral placement to boost production

In expanding its focus in the Mississippian play in southern Kansas, SandRidge Energy Inc. was able to develop an entire section—640 acres—from a single wellbore for $5 million, which is a 44% reduction compared to the standard single-well model. The company considers its multilateral development—dual and trilaterals and stacked laterals from a single vertical wellbore—to be game-changing.

“We have some ongoing and exciting completion initiatives that are showing some significant positive results,” said Aaron Reyna, senior vice president of development for the Kansas Business Unit at SandRidge, during the company’s investor/analyst day March 4, 2014. “We have an implementation of a multilateral sectional development that we see will lower capex and really improve our returns going forward.”

The company’s push into the Sumner County area is a result of extensive work done by its geosciences and engineering teams to understand the geology. By tying the geology back to the development that was going on in Oklahoma, the company has been quite successful with it, he continued.

FIGURE 1. The first trilateral was drilling in September 2013. An entire section was developed from one wellbore, saving about 44% compared to a typical three-well program. (Source: SandRidge Energy)

“The economic performance of this play is very encouraging and solid. We’re seeing an internal rate of return for this project at 74%. The success of the project has added a little more than 115,000 acres to our focus area. We plan to drill 45 wells in this project in 2014,” he continued.

Game-changing multilaterals

SandRidge has three multilateral prototypes. The first trilateral well was drilled in September 2013 with a total of 4,421 m (14,500 ft) of reservoir and completed with 55 stages of hybrid acid/water design (Figure 1). The well used a retrievable inflatable-packer system that was developed in Canada. Six multilateral sections are planned for 2014.

“The single most important thing is that the first trilateral well officially developed an entire section for $5 million. It is very, very cost effective. In the past, we would have teed up and drilled three single horizontal wells and built three tank batteries. The effort has yielded a successful mechanical result. We’re currently evaluating the performance results,” Reyna explained. “Three different prototypes of wellbore design have been implemented successfully as part of our 2014 program.”

The company has two additional prototypes. “The stacked lateral development is very important based on the stacked plays we’re seeing in the Midcontinent,” he said.
Currently, for the stacked lateral, wells are being completed in two formations. One well is being tested, one is being completed, one is being drilled and five wells are planned (Figure 2). Estimated savings are about $1 million compared to drilling two single horizontal wells. The company is now drilling the first of five planned wells. Drilling time has been reduced by six days. This design is scalable for multiple areas with stacked formations, he noted.

FIGURE 2. One stacked lateral development well has been completed and is undergoing testing. (Source: SandRidge Energy)

The third prototype is the dual-lateral development. If drilling three laterals from the same wellbore in a single formation is successful, then why now drill two?

“What we’re targeting with the dual-lateral development are those areas where we may be landlocked and not able to control 640 acres [Figure 3]. The two-lateral plan will allow us to develop a half-section of property,” he said.

Redesigning mechanical completions

SandRidge sees additional opportunities for enhancing its program economics through its downhole mechanical design changes. The company is using two different mechanical configurations—an openhole packer system and a chemical-packer/sleeve-tool system—to reduce completion costs and allow use of natural fractures that are necessary for production.

Its openhole packer-completion system is used in 95% of the wells in its current program. “We’ve continued to maximize the efficiency of our completions. We’re now running openhole packer systems that allow production from the entire section, which is not [obstructed] by cement and is what we typically see in older designs,” he said. “We’re also running electric submersible pumps [ESPs] at 90 degrees. These provide the lowest possible pressure for the life cycle of the well.”

FIGURE 3. The dual-lateral development will be used in areas where the company does not control a full section. (Source: SandRidge Energy)

Stimulation is an integral part of the success of the program. There are two generalized methods for initiating fractures. The one generally accepted by the industry is planar. This completion included a cemented 4½-in. production liner, standard 10-stage stimulation and 52-degree ESP installation. The cost to drill and complete the well was $3.12 million. The 180-day cumulative production was 62,200 boe.

With the openhole packer system, SandRidge uses dendritic stimulation, which involves cycling the pump to create additional fracture networks near the wellbore. This included a 10-stage stimulation with a 90-degree ESP installation. The cost for drilling and completing the well was $2.93 million. The 180-day cumulative production was 102,600 boe.

“The dendritic design is the one we’re physically employing at the present time. It is the result of cyclical pumping during each individual stage. What this means is that we’re actually contacting more surface area, which is beneficial to the performance of a well,” he emphasized. “What we’re doing right now has been cost-neutral relative to stimulation costs from what we did in the past.”

To date, the company has completed 19 wells with the new design. “We’re seeing a conservative uplift in EUR of about 15% relative to the offset planar design wells,” he added. “With the 180-day performance, there has been a 68% performance gain with the dendritic design.”

The second system being used by SandRidge involves a chemical packer, which is a temporary gel system for hydraulic isolation, and a sleeve-tool system. This design allows the company to access the wellbore through the liner that is being run. It is a sleeve and plug-and-perf combination that is extremely fast. This system saves about $60,000 per well and takes less than two days to stimulate vs. an original design of six days, Reyna explained.

“I am very excited about the chemical-packer and sleeve-tool system. We believe this can really be a game-changer under the correct applications. A well savings of $250,000 can be expected and projected with this system. It uses polymer gel instead of permanent cement. It also uses a fully retractable liner,” he said.

“I was part of a program in the Permian Basin in 2012 that successfully implemented this in a similar carbonate reservoir, type and fracture. We performed 36 jobs, and all were mechanically and operationally successful. It has already been employed in a well in Oklahoma with operational, mechanical and economical success,” he continued.

“Our stretch goal is to get to $2.3 million per well. One of the things we’re excited about moving forward is to continue to drive costs down. These design changes are going to supplement our efforts with multilateral development plans,” Reyna emphasized.