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Scott Bolton
PriceWaterhouseCoopers LLP

The technology that unlocked the massive shale gas prize — horizontal drilling and multistage fracturing — has hardly skipped a beat as it jumps to a new host in emerging tight oil and liquids-rich plays as well as “vintage” oil plays across the North American continent, including the Bakken and the Viking of Saskatchewan and the Cardium of Alberta.

The move by industry to horizontal well exploitation of Western Canada’s less permeable reservoirs using multistage fracturing is picking up speed in 2011 after setting new records last year.

In 2010, a little more than 5,000 of the wells drilled across the four western provinces were horizontal holes, or about 42% of all wells drilled (excluding oil sands evaluation wells), setting a new record.

Industry licensed 2,433 horizontal wells during the first three months of 2011, up 69% from the first quarter a year ago, setting the stage for another record year for horizontal holes. Excluding oil sands evaluation and experimental well licences, the 2,433 horizontal licences represented about 55% of all wells approved for drilling.

A new breed of producer

Driven by technology, there are enormous implications generated by industry’s ability to economically produce reserves of hydrocarbon previously inaccessible in tight reservoirs. Many of the new breed of Canadian junior and intermediates are leveraging horizontal drilling and multistage fracturing to make relatively rapid and significant production gains. It is also boosting the value of these companies.

The play types these companies are chasing vary from infill drilling that benefits from stronger rates provided by horizontal drilling to plays that historically have had only limited well penetration.

In June 2011, companies spent $843-million to snap up oil and gas land in Alberta, establishing a new record for bonus revenue at a single land sale. For some of the larger bonus bids in west central Alberta, some analysts believe producers are targeting oil or liquids-rich natural gas development in the Duvernay play.

Older, “vintage” pools known to be productive are seeing renewed industry attention as recoveries can be increased significantly using horizontal drilling and multistage fracturing. In these pools, it’s not a question of finding the resources, but of exploiting them economically and to “squeeze” more production out of the rock.

As such, there is an increased imperative to reduce operating costs, especially as the costs to drill and complete horizontal wells are much greater than drilling vertical wells. (At one time, a junior could set up shop with $5 million and drill several vertical wells. Today, the cost to drill and complete even 1 horizontal well can range from $3 million to $4 million, or higher depending on completion costs, so the oilpatch has become a much more expensive place to do business.) As producers increasingly target resource-style projects, there is a tremendous competitive pressure to innovate — both below-and above-ground.

Below-ground innovation includes drilling advances (extended reach, laterals, placement), delivering more intelligent fracs (spacing, size, choice of fluids) and subsequent reservoir management (isolating zones, remote activation of downhole tools).

Above-ground innovations include advances to supply chain logistics, modularization and sustainability.

Managing the shift from shale gas to tight oil

Just as the technology combo had to be adapted to each new shale gas play to be a success, producers are also adjusting the techniques for emerging tight oil plays.

Because there are many new play ideas that can be generated by applying the new drilling and completions technologies to existing maps and geological knowledge, industry has to recalibrate its mapping to identify what is most prospective.

With little in the way of detailed analysis undertaken or historical evidence to draw on, many companies are relying as much on trial and error and imitation as on hard data and science to complete their wells, say some producers.

Operators will be able to optimize production if, instead of imitation, they complete the technical work necessary to understand the technologies they’re using and to calibrate predictions with actual data.

Despite their similarities in benefiting from horizontal drilling and multistage fracturing, tight oil and shale gas development need to be approached differently.

"As producers increasingly target resource-style projects, there is a tremendous competitive pressure to innovate — both below-and above-ground."

For instance, some tight oil producers are spending more time trying to work with their frac fluids and jobs aren’t nearly as big. Tight oil pay zones are generally thinner, so producers are working with a much more confined rock layer.

The Canadian Bakken, for instance, is a lot thinner and shallower than its American cousin and has neighbouring water zones the U.S. generally lacks, so multistage fracturing has to be approached delicately.

To get good coverage and make it economic, some Bakken producers use more fracs but they are a lot smaller and are pumped at much lower rates. Producers have found it is important to decide on optimum well length, fracture spacing and well spacing very early in the field development program. Analytical modelling can be a useful tool to then provide a forecast of initial production and cumulative production recovery over time, thereby showing what type of recovery may be possible.

Development challenges

Even though the potential of tight oil is enormous, there are major challenges to overcome before producers achieve the much-touted potential.

As with the shale gas, the biggest question is whether tight oil production growth is sustainable. When multistage fracturing is performed, wells are worked harder, leading to a faster decline compared to traditional vertical wells.

Boosting the number of fracs is sometimes used as a strategy to inflate initial production rates, but may be at a longterm cost to overall production.

Some producers believe that additional fracs can interfere with each other quicker, leading to a higher decline rate and ultimately no more recovery than by using fewer fracs (i.e. more is not necessarily better.)

Other tight play development concerns include labour and service cost escalation issues.

Tight oil development will only add to the labour pressure in Alberta. The province has its fair share of tight oil plays, as well as ongoing oil sands development. A comeback in gas prices would significantly pressure labour and service costs.

In addition, environmental issues surrounding fracturing are still outstanding — as they are with shale gas development — with green groups and landowners concerned about the effects of fracturing operations on water supplies. The social license to operate is significant and must be considered.

There’s another parallel with shale gas development. Could we see the creation of a North American “oil island,” with wide differentials, due to the influx of additional crude volumes into the continental market?
With the potential addition of significant tight oil from U.S. plays alone (2 million barrels a day by some estimates), it may be a scenario to consider.

Scott Bolton is the Canadian Energy leader for PriceWaterhouseCoopers LLP.