July 2017

Increasing the odds of successful refracturing

Combining an in-depth field analysis with mechanical isolation and a targeted stimulation treatment will greatly enhance the success of a refracturing program.
Matthew Miller / Packers Plus Energy Services

Horizontal drilling and completions have evolved over the last decade, such that multi-stage horizontal wells have become standard practice. Many of these horizontal wells show significant production declines during their first two years of production. As a result of sustained low oil prices, and an operator’s need to maximize the net present value of reserves in each drilled well, the possibility of refracturing existing wells has gained significant attention.

Defining specific production uplift goals, and selecting the right candidates, are paramount in realizing economic benefits associated with a refracturing campaign. Since not all wells are good refrac candidates, it is important to select wells that are likely to deliver a financial return on the refracturing investment. Once the right candidates are selected, deploying a completion solution, using mechanical isolation and targeted zone stimulation, will greatly increase the potential success of a refracturing program.


Selection of a refrac candidate well is arguably the most important phase of the refracturing process. There is more involved than simply selecting wells that are not producing to a field standard and pumping a second treatment.

Since producing standards and field characteristics will vary across a given reservoir, specific criteria that go beyond decline curve analysis and mechanical integrity concerns should be integrated into the process. Treatment information, such as tracer logs, production charts, temperature profiles, etc., can be used not only to gain an understanding of the current producing intervals, but also as a means of selecting new injection area(s) within the well. 

By using production data, a basic understanding of a field’s productive potential can be obtained. This also can help to identify which wells may have been under-stimulated. The plotting of well performance over time indicates how strong a well was initially, and where it now stands in relation to others in the field. These production data can be used to help determine damage mechanisms through a rate transient analysis.

This quantitative differentiation of performance is the first step in recognizing which wells may yield the greatest incremental returns. Considering field-wide performance distribution, some limits can be set to establish the target productivity, and to group wells into performance categories. Looking at the field in this way allows for recognition of the extent of the field in question. 

Fig. 1. Production map, showing potential refracturing candidate wells, as they relate to location within the field.
Fig. 1. Production map, showing potential refracturing candidate wells, as they relate to location within the field.

 The next step is to gain an understanding of the spatial distribution of well performance throughout the field. Qualitative analyses of production characteristics are needed, to indicate whether a well is likely to be under-stimulated, is outside the production fairway, or may have some combination of geologic, wellbore integrity or other factors that accounts for comparatively marginal productivity.

A production map enables expeditious identification of anomalous under-performing wells and serves as an easy way to cross-check with the initial decline curve analysis. For example, in Fig. 1, wells in the center of the fairway are generally good producers, as quality of production diminishes toward the edges of this identifiable group of wells.

This “fairway map” is most often an expression of reservoir quality and favorable geologic conditions. As presented in Fig. 1, there are a few wells within this cluster of good performers that don’t quite measure up, and so these become the highest-potential refrac candidates. 

After identifying outliers as top refrac candidates, a specific well-scale analysis is needed to further reduce the list. This includes a review of the initial hydraulic treatment data, and analysis of geologic conditions, reservoir maturity, and fluid properties, as they might pertain to paraffin, asphaltenes and scaling.

Additional geomechanical and fracture modeling, and their influence on offset wells from the initial stimulation, should also be considered. It is important to note that once a candidate is selected, assessing operational risk related to wellbore integrity, and the potential for offset well communication, needs to be addressed.

While legacy data are an economical method of evaluation, the level of desired wellbore resolution may necessitate additional data acquisition. Obviously, this ties into economic considerations, such as the production metrics established by the company, estimated return on investment, and a cost benefit analysis. All these data sets, taken together (as available), serve to assist in the determination of the final refrac candidates from a risk and economic perspective.

The final step in candidate selection is the design of the treatment and completion system. At this point, factors, including the heterogeneity along the lateral, fracture types and distribution, and reservoir petrophysics, are combined with the existing completion design, to further subdivide the well into productive, marginal and non-contributing areas. 


There are two main strategies for refracturing, as shown in Fig. 2. The first is to re-establish or enhance conductivity of the existing hydraulic fractures that are damaged, or are non-contributing, by treating them again. 

Fig. 2. The image on the left shows the first refracturing strategy of correcting damaged and non-conductive fractures with a refrac. The image on the right shows additional fracture creation, with enhanced fracture geometry in previously established fractures.
Fig. 2. The image on the left shows the first refracturing strategy of correcting damaged and non-conductive fractures with a refrac. The image on the right shows additional fracture creation, with enhanced fracture geometry in previously established fractures.

 In some of the first horizontal wells, the stimulation treatment may have been insufficient, or depletion processes may have resulted in a choke point within the fracture that effectively limits conductivity. By increasing the conductivity within these fractures, near the wellbore, production restrictions are minimized and reserves can flow more freely into the well. In other instances, fines migration and/or asphaltene and paraffin accumulation could have clogged up or sealed off the fracture, limiting production. Through a refrac treatment, conductivity of the existing hydraulic fracture is renewed, resulting in a spike in production following treatment. 

However, it is important to note that this production spike is short-lived. Based on historical evidence, improvement in near-well conductivity temporarily increases production; however, the output decline returns to the expected initial curve and production levels, as before the refrac. This temporary change is an indication that no new reserves were effectively accessed.

The second refrac strategy is to access previously unstimulated reservoir rock by creating a stimulation design that will contact additional under-stimulated/unstimulated portions of the well, and increase the fracture surface area. This can be accomplished by creating additional fractures along the lateral, or through a larger treatment that reaches further into the formation.

Updating fluid design parameters, or the use of a more sophisticated, reservoir-specific fluid system, can benefit these efforts further by reliably generating, and effectively propping, longer, wider and more complex fractures than those created during the initial treatment. Candidates may have suffered from treatment failures, or skipped stages in the original stimulation.

Also, consider older wells that were completed before advancements occurred in multi-stage isolation and completion technology. By implementing newer technologies in older wells that have long stage spacing, or lacked stage isolation completely, additional reserves would be obtained. These wells are the lowest hanging fruit, and represent an opportunity to effectively isolate and treat additional stages throughout the lateral. The biggest challenge to this strategy is effectively isolating and treating newly perforated intervals.


Another way to target new reservoir rock requires recognition of the effects that the altered stress state has on the new fracture system that is generated. During well planning, a hole is usually drilled to take advantage of the reservoir stress state, to encourage fracture growth in a certain direction relative to the wellbore, typically transverse. 

Fig. 3. Stress field reorientation after initial stimulation and possible reversal of SHmax and Shmin direction, resulting in new fracture geometry creation.
Fig. 3. Stress field reorientation after initial stimulation and possible reversal of SHmax and Shmin direction, resulting in new fracture geometry creation.

 As such, the fracture network created from an additional treatment may contrast significantly with the one that was created during initial treatment. The new fracture network created in the mature well will be influenced by decreased pore pressure, as well as decreases and changes to the principal stress magnitudes and directions. Stress field rotation and pore pressure decrease will now, potentially, result in a new fracture azimuth that deviates from what was seen initially, as shown in Fig. 3.

Case studies have observed varying scales of stress field rotation and fracture
reorientation, ranging from minor azimuthal deflections around 15°, to complete reversal of the minimum and maximum horizontal stresses, causing longitudinal fracture propagation. In some cases, complex geometry created by a refrac treatment in the altered stress state would have a positive impact on production, but undesirable outcomes are a very real possibility in areas of low horizontal stress differences. If there is a large, native, horizontal stress difference, this type of dramatic change to the stress field orientation is less likely.


Temporary isolation. There are a variety of techniques used to implement the strategies described above. Diverters and ball sealers, known as temporary isolation systems, are injected during the secondary treatment process. 

During this process, a chemical agent or a biodegradable material will be injected at certain points during the treatment, with the intent of distributing fluid to areas where fracture conductivity can be improved, or no injection occurred previously. The thought is that this material will seal off existing, highly permeable fractures, leading to an increase in treatment pressure that will ideally break down new formations or enhance conductivity of existing, lower permeability fractures. 

After the treatment is complete, the material either breaks down through a chemical process or is flowed back to surface during the fracture clean-up. However, given that the entire well is usually stimulated all at once, as a single treatment, it is difficult to determine the success rate of this technique, due to the inefficiencies of fluid distribution across the entire wellbore.

The production increase could be associated with several things: new unique fractures in untreated rock, enhanced fracture geometry in previously established fractures, or re-establishing conductivity in the original fractures. Because of non-uniform fluid distribution, these treatments usually favor the heel of a well, leaving the toe untreated.

Mechanical isolation. The technique that delivers sustained returns on investment in refracturing incorporates mechanical isolation. This usually means an additional completion system is installed in the well, in conjunction with the initial completion system. This system provides isolation from previously stimulated areas. 

Mechanical isolation systems include: slimhole ball-actuated, expandable liners, coil tubing intervention, and cemented squeeze jobs that incorporate additional perforations. Although all these systems are unique, they are linked together by use of mechanical diversion and the ability to focus treatment in desired locations along the well.

The operational aspects of using these systems are more involved than typical diversion jobs. As such, steps must be taken to ensure that the initial completion system and wellbore are congruent with the installation of the second system. This usually includes some method of ensuring that the inner diameter of the wellbore is not restricted; cleaning out the wellbore; initiating additional perforations in new zones of interest; and ensuring pressure integrity in areas of interest.

A major benefit of the mechanical isolation approach is that these types of systems allow for flexibility of design. With the assurance of mechanically isolated zones, stimulation into previously untreated rock, as well as isolation of known water-producing intervals, can benefit production over the wellbore’s lifetime. This technique requires the largest capital investment,  but if properly executed, mechanical isolation systems provide the greatest probability of economic success.


Moving into the fluid treatment design phase, the objective of the refrac will need to be considered. As with the initial fracturing treatment, parameters such as rate, proppant transport, fluid viscosity, and formation compatibility will influence the final design of the refracturing effort. Current reservoir and pore pressure need to be accounted for, since fractures will grow rapidly and more readily into areas of depletion. Selecting a gel, slickwater or acid fluid system can exaggerate these conditions, and increase the risk of fracture communication with offset wells. Recent studies have shown that smaller job sizes, combined with larger proppant concentrations, have led to higher production rates in some refrac wells.


The following is an example of success that an operator can have when effectively isolating and stimulating new pay zones in mature wells. 

Fig. 4 Slimhole system enables exact placement of stimulation treatments in one continuous pumping operation saving operators time and money.
Fig. 4 Slimhole system enables exact placement of stimulation treatments in one continuous pumping operation saving operators time and money.

 An operator targeting the Cotton Valley Lime in Texas completed a five-stage, cased hole, horizontal well in Farrar field during 2008. The well reached peak production in September 2008, with a monthly volume of 7,493 boe. In less than three years, production plummeted.

The operator decided to run a five-stage Packers Plus StackFRAC Slimhole (Fig. 4) system on a 2.875-in. liner. It is designed to isolate individual stages by mechanical packers, segmented by ball-actuated sleeves, to more effectively stimulate portions of the reservoir that were bypassed previously.

New perforations were shot into the cemented casing, as per the operator’s design, and the well was restimulated with a slickwater treatment and 400,000 lb of proppant. Figure 5 shows the production curve for the well.  Average monthly output for the five months following refracturing was 2,685 boe, or 1.5 times higher than the average monthly boe for the five months prior to restimulation, which was 1,072 boe. As a result of the operation’s success, the operator was not only able to keep the well online, but able to add proven reserves that increased the field’s NPV for a minimal cost.


Successful refracturing involves detailed understanding of the factors behind poor well performance. Significant production decline, after initial output, in many horizontal shale wells is a challenge.  Refracturing can improve conductivity of the existing hydraulic fracture network, and access reservoir rock that was bypassed or under-stimulated in the original completion.

Fig. 5. A successful isolation and refracturing job after 35 months of initial production.
Fig. 5. A successful isolation and refracturing job after 35 months of initial production.

Marginal results of many of the initial efforts at refracturing have shown that the production benefit may only cover the cost of the operation. A successful refracturing program requires more research and design than simply pumping a treatment. 

In some cases, the economics of drilling another well are more attractive, in terms of net production increase for the operator. To counter this, and create additional NPV for existing wells, a focus on refracturing methods that provide a sustained production increase is needed. 

By using integrated analysis that focuses on specific goals, operators and service companies can determine the most beneficial course of action. Programs that proceed with an understanding of the benefits and limitations of each refrac technique will be more successful. Through the installation of a completion system that has the ability to provide reliable zonal isolation along the lateral, and allows for flexibility in design, significant steps forward in profitable refracturing can be achieved. wo-box_blue.gif

About the Authors
Matthew Miller
Packers Plus Energy Services
Matthew Miller is the Fracture Sciences research engineer for the Fracture Sciences Group at Packers Plus Energy Services Inc., working out of the firm’s Denver, Colo., office. He provides interpretation of data sources, including treatment designs, completion methods, formation characteristics, etc. and their effects on production. After earning a BS degree in petroleum engineering from Colorado School of Mines in 2010, Mr. Miller worked for Halliburton Company for two years as a hydraulic fracturing field engineer, with experience in numerous plays and formations throughout the Rocky Mountain region. He joined Packers Plus in 2012.
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