Well worth the attention

Effective strategies are increasing initial production rates and ushering in new completion practices in the Williston Basin.
By Luke Geiver | September 06, 2013

Retrieving oil from the Williston Basin is almost a guarantee for those who deploy the appropriate capital. Today, with new well-completion strategies, hydraulic fracturing teams and producers have the ability to turn a well-pad into a record-breaking site regardless of the well’s geographical location. The strategies aren’t just about extracting more oil out of the reservoir. Some new completion methods are lowering the cost of doing business while retrieving a greater amount of the recoverable oil in less time.

Proppant Placement Evolution
CARBO Ceramics is the world’s largest ceramic proppant supplier. Terry Palisch, director of petroleum engineering for CARBO, says the company isn’t just about proppant supply. “We are trying to help clients with their proppant selection so that it maximizes their return on investment,” he says. To do that, Palisch and his team sit down with prospective clients to better understand that client’s wells, completion preferences and frack design plans. “Then we will run models to help them determine what is the most economic proppant to use for their specific conditions and goals.”

The CARBO approach to proppant selection may not have been as widely used five years ago, but today the emphasis on proppant selection and usage in the Williston Basin is undeniable. According to the Energy and Environmental Research Center, from 2008 to 2012 the amount of proppant used on a pound-per-foot of lateral-length basis increased from 100 to 350. During that same period, the ceramic fraction of all proppant used increased from 10 to 40 percent. And, the average number of fracture stages per well rose from roughly 10 to roughly 30. “Of all the major plays in the U.S., the Bakken employs more ceramic proppant than all the others,” Palisch says.

According to Palisch, the increased focus on proppant isn’t just about volume, as producers are now taking a close look at the type, size and placement of proppant. As a proppant material moves from sand to a ceramic, the proppant will gain strength, consistency in shape and temperature stability. In the proppant spectrum, there are three types: ceramic, resin-coated sand and uncoated sand. All three are used in the Bakken, and Palisch says all three must be used because there is not enough ceramic to go around.

The product with the most conductivity or flow capacity is ceramic, followed by resin coated sand and uncoated sand. The CARBO approach to proppant is unique, Palisch says, because the company deploys an engineering and design team along with computer modeling to pinpoint the appropriate proppant size and type for any given well. “As an industry, we want to get to a standardized completion design,” he says, a design that can be used in particular areas for most wells in that area. “By doing that you can really be efficient; unfortunately you may sacrifice the optimal completion because even over a short distance a reservoir can change substantially.”

Due to heterogeneous and reservoir characteristics, a typical completion design may not be possible to achieve for an entire field in the Williston Basin, but well optimization can be. Several factors have to be considered for an operator as it creates a frack design and completion program in accordance with budget constraints or concerns, but there are proven approaches some are using to increase production without increasing the budget. “The decision the engineer has to make is a cost-benefit decision,” Palisch points out.

One major trend Palisch has seen is related to proppant placement. He compares the trend to downtown Houston. To efficiently move more traffic into downtown Houston, the city requires more lanes and highways closer to the city than it does in the suburbs because traffic from several areas are moving towards a single area. “That is exactly what we are doing with our hydraulic fracturing. We are putting these roads and highways out into the reservoirs,” he says. The closer to the well bore (Houston), the more fracture-flow capacity and conductivity is needed as oil from the furthest sections (suburbs) of the fracture are moving towards the heel and then the wellbore. 

To optimize a well, completion teams are placing different types of proppant in different sections of the fracture. Many are placing high-conductivity, engineered proppant that offers uniform shape and consistency in the last third or half of the hydraulic fracture closest to the wellbore.  The tip of the fracture may be stimulated with sand, a less expensive product. “That is how they are able to maximize production without spending as much money,” he says, by creating a better highway system near the wellbore that acts as the city and helps to move a greater amount of oil out of the reservoir faster.

The Completion Business
NCS Oilfield Services does not have the size or scope of business that CARBO Ceramics does. The company does believe in the power of retrieving oil as fast as possible, though. The firm has designed, and proven a system capable of an unlimited number of fracture stages. To date, the record for the company is 60 discrete fracture stages. The basis of the NCS process is a mechanical system that combines ported fracture sleeves with a bottom hole assembly tool that eliminates the need for perforations that puncture a well casing, and ball dropping, which is used to portion off and plug one section of a well from another. The main benefit of the process is that is allows users to place fracture stages at nearly any interval without removing the entire system between fractures.

Eric Schmelzl, vice president of business and part designer of the process, says that one operator in the U.S. recently issued a Society of Petroleum Engineers paper comparing a plug-and-perf cluster operation with the NCS technology on a two-well pad. Each well was completed with 27 fracture stages, but each well used a different approach. “After several months of production they plotted the expected recoveries of each well. The NCS technology is expected to recover 107 percent more than the other well,” Schmelzl says.    

The secret to the NCS approach is the ability of the operator to place individual fractures with great certainty. In most cluster fracturing instances, enough pumping horsepower and fluid is used to place three fractures at once, and operators can only expect to be certain of one to two of the fractures, Schmelzl says.

“Sixty-six percent of the fractures you are placing in that well, you are uncertain about,” he says. “It becomes a real Russian roulette to well completions—you don’t know what you did, you only know what production you got.”
The cost to use a technology like that of NCS’s versus other methods is nearly a wash due to the decreased amount of horsepower needed at the well site for pumping purposes. The time to complete a well does take longer, but the result is a well that gives more fracture placement certainty to the operator combined with the ability to place an incredibly high number of fracture stages.

“When you stop and think about the economics of completing the well, by putting in additional frack stages of equal size in, you are accelerating the speed at which you drain the reservoir,” he says. “When you look at the time value of money, having your money this year is worth more to you than having it next year.”

Initial production rates are benefiting from the strategies focused on proppant placement and increased discrete fracture stages. The cost-to-benefit ratio is still a major reason why some wells produce at record breaking levels, however. And, according to Dale Larsen, account manager at CalFrac Well Services Corp., the lateral lengths used in the play are also helping. Larsen’s customers are now preparing for three-mile laterals. “We are going to see the longer horizontal lengths,” he says, “and continue to see more stages per more well bore.”

The practice of longer laterals may add costs during drilling, but as Schmelzl says, the producer doesn’t have to waste money on drilling down to the second lateral. “It can have a significant economic impact if you are able to function reliably two to three miles sideways,” he says.

The effect of longer laterals, increased fracture stages and sophisticated proppant placement programs will all help producers to retrieve a greater amount of crude from the reservoirs, in some cases, faster. There is a trade-off, however. The time to drill and complete the wells will increase.

For companies like CalFrac, a mid-sized fracking company capable of handling major drilling schedules, or small-time, one-well-per-year programs, the recent trends seen at the well site do require a new approach. “Although a lot of other processes have stayed the same,” Larsen says, “the time on location is going to increase.” Because of that, companies that offer the services CalFrac does will need to tweak its long-term manpower planning. In some cases, companies will need to keep rotating crews at a well site for a longer period of time.

“When there is an inventory of uncompleted wells sitting out there, there is going to be a demand for our service,” he says. “Oil and gas producers don’t like to have a well sit, they want to get it producing as soon as possible so they can start seeing cash flow.”
Author: Luke Geiver
Managing Editor, The Bakken magazine