Shale’s low permeability means oil and gas molecules move very slowly, often as little as 0.3 m to 0.6 m (1 ft to 2 ft) per year. As a result, for horizontal wells in these reservoirs to produce economically and achieve acceptable recovery rates, the well stimulation treatment must achieve three goals:

  • A fracture network must be created through hydraulic fracturing to connect more hydrocarbons to the horizontal wellbore;
  • The fracture network should be as large and complex as possible; and
  • The conductive fracture area—the overall area of the total created fracture network that does not seal upon fracture closure—must be maximized.

Enlarging the fracture network

The industry has begun to recognize the link between conductive fracture area and the effectiveness of the fracturing treatment to contact the reservoir. Today many unconventional shale stimulations are performed, in part or in whole, with low-viscosity fluids. These fluids have a lower associated breakdown pressure than their higher-viscosity counterparts and so do not limit far-field fracture complexity.

The drawback to the low-viscosity fluids is that they cannot provide perfect proppant transport characteristics. Conventional proppants (most often sand) have a specific gravity that is significantly higher than the fluid in which these are pumped, making it extremely difficult to place proppant above the horizontal lateral (i.e., the high side of the created fracture network). Instead, the proppant settles and creates a bank, or dune, in the bottom of the fracture at or below the depth of the horizontal lateral wellbore. Any proppant that might reach above the lateral wellbore typically settles before the fracture closes. As a result, the fracture above the lateral is either choked or shut off—sacrificing much of the total generated fracture area when the unpropped section seals.

A common approach to improving production from stimulated wells is simply to increase the overall size of the stimulation by pumping larger fluid and sand volumes. While the larger volumes of water and sand can develop a larger fracture area, this process often fails to produce an equivalent production response—again, because the majority of the proppant is placed in the bottom portion of the fracture without the ability to prop open the upper fracture area above the lateral wellbore. Although larger, the unpropped fracture area still seals, and any additional production that may occur is often a benefit of the increased fracture length.

Another approach is to pump a hybrid fluid design wherein the last portion of the treatment is composed of crosslinked fluid and proppant. The proppant becomes entrained within the fluid’s crosslinked long-chain polymers. It is then transported down the well and to its final position within the formation. This approach allows placement of some proppant above the depth of the lateral wellbore. However, the overall coverage area is limited proportionally to the entire treatment volume. Additionally, the crosslinked tail-in sand stages that are placed above the lateral tend to settle in the fracture due to gravity effects. As crosslinked fluid stages begin to break and thin, they lose the ability to fully support the sand. When combined with the extended fracture closure times associated with very tight reservoirs, there is no confining force to completely inhibit the suspended sand from settling prior to closure.

Reaching above the lateral

To achieve the goal of maximizing the stimulated fracture network using low-viscosity water-based fracturing fluids, Baker Hughes developed its Ascent fracturing service. The service applies advanced modeling and specialized pumping techniques to deliver and effectively place strong, ultralightweight proppants in water-based fracturing fluids above the depth of the lateral. The extremely strong “buoyant” proppants replace a portion of the sand during the stimulation treatment to ensure that a significant portion of the fracture’s high side remains open following fracture closure. Because they are nearly the same density as the fluid, the ultralightweight proppants will not fall to the bottom of the fracture, even during extended fracture closure periods, greatly expanding the conductive fracture area and significantly increasing the effectiveness of the stimulation. The size of each stage treatment may even be reduced while still accessing more total fracture area.

An additional benefit of this approach is that it reduces fluid and proppant requirements and with them multistage stimulation times, operational costs and HSE risk. One pound of ultralightweight proppant can replace on the order of 10 lb of sand, thus reducing the volume of sand required by 30%, 40% or 50%, depending on reservoir characteristics. The lower sand and chemical requirements reduce associated rail and truck transportation cost, traffic and risk. The resulting improvements in well economics and the improved production benefit both sides of the cost-per-barrel equation.

Determining treatment program, pricing

To determine the best treatment design and pricing for the stimulation, treatments of current and previous wells are modeled. The model is then optimized to predict the increase in conductive fracture area that can be expected by treating with the optimized service. Consultation between the operator and the service company determine which treatment size best fits the stimulation goals for a particular reservoir and well configuration. The treatment is executed.

Production monitoring from long-term studies shows that the most significant improvements from using the new treatments are not always visibly apparent during the initial production period. The greatest improvement becomes apparent with cumulative production over time—months and even years into production. Wells stimulated using this approach produce longer with steeper cumulative production climb because of more contributing fracture area within the reservoir.

The additional increased conductive fracture area can also contribute to a reduction in the production decline rate over the long term. It can improve the boe cost of production from either any realized increase in production or associated savings from a more effectively placed stimulation design, or both.

Case histories

In a 19-well, 36-month study in the Barnett Shale in Texas, using the company’s fracturing service enabled operators to increase hydrocarbon recovery by an average of 117% over conventionally treated wells of similar depth and length within a 3.2-km (2-mile) radius. Proppant volumes were lowered, and water usage decreased 20%, from 19,163 l/m (1,543 gal/ft) to 15,189 l/m (1,223 gal/ft).

Similar results were reported from a 16-well, 72-month production study in Hughes County, Okla. In Coal County, Okla., hydrocarbon recovery increased by an average of 28.2%, while proppant volumes dropped a dramatic 48%, from 1,220 kg/m (820 lb/ft) to less than 624 kg/m (419 lb/ft), and water usage also decreased.

In current market conditions, both operators and service companies are focused as never before on improving efficiencies in all aspects of well construction and production. The fracturing treatment described in this article is one option in a fracturing service that exemplifies how the industry is developing smarter, better engineered solutions to deliver stimulation treatments that are more efficient in the short term, more effective in the long term and more economic throughout the life of the well. Additional options based on new proppant and fluid technologies are expected to be introduced later this year.

Comments