Sleeves vs. Shots – The Debate Rages

The PNP technique follows traditional completion procedures. A cemented liner can be set through the completion interval, or an uncemented liner can be used. A plug is attached to the bottom of a perforating gun and conveyed into the well. Any method (pump-down, tubing-conveyed perforating, wireline tractor-assisted conveyance or coiled tubing) can be used to position the plug/gun combination in the lateral. The plug is set at the appropriate depth below the toe zone and shears off. Then, the gun is pulled uphole and positioned precisely opposite the first zone to the stimulated. The gun is fired and pulled out of the hole. If desired, several intervals of the same stage can be shot using select-fire guns on the same trip. When the stage has been treated, the next gun/plug combination is deployed, and a composite frac plug is set to protect the zone. The process is repeated for the next stage. Although all stages are preplanned, the operator can change, delete, or add a stage if observations indicate such a deviation from plan is advantageous.

Another type of PNP treatment involves ultra-high pressure abrasive jetting that is deployed on coiled tubing to perforate and treat individual intervals. Usually, a sand plug is set to protect previously treated intervals as the process is repeated for subsequent stages. The abrasive jet technique is used mostly on shallower wells but has the same flexibility as conventional PNP.

An earlier PNP technique that rarely is used now involves setting an uncemented liner in the lateral and treating the formation through perforations made at selected intervals. The theory behind this is that the formation will always fracture at its point of least resistance. Of course, this could be into an aquifer or an offset well. Most operators are no longer using this technique because of its unpredictability and the introduction of real-time microseismic fracture mapping.

Depending upon the number of stages to be treated, the PNP technique can take several days or more. The big advantage is that since each stage is treated individually, decisions can be made on the fly to change the location of the next stage, add or delete a stage, change the interval perforated, and so on – in other words, PNP affords complete flexibility. The PNP technique also favors the implementation of advanced treatment techniques such as Simul-frac or Zipper frac.

Factors influencing the choice of technique

The savings in cost was listed by 66% of the respondents as the primary factor influencing their decision to use one technique over another. Higher well productivity was cited by another 20%. Therefore, the primary drivers are speed for cost savings or flexibility for higher well productivity. The poll also showed that in 80% of cases, the operator rather than the service company makes the decision. But the decision is seldom obvious – operators appear to be stymied in choosing OHMS vs. PNP because other factors play into their decision.

There is no question that the OHMS technique is considerably more efficient in terms of field operating time, and the gap grows as the number of stages is increased. Several years ago, conventional wisdom held that a few widely spaced long-length fractures were the best way to fully exploit the reservoir and ensure maximum estimated ultimate recovery (EUR). Using a popular rule of thumb to double the frac length, one must quadruple the volume of treatment pumped. This increases the possibility of problems and adds to the cost. Recent experience has shown, however, that numerous closely spaced short fractures produce better results over the life of the reservoir. This outcome would seem to tilt the scale in favor of OHMS owing to its superior efficiency, but OHMS is not the predominant technique in many plays.

The survey revealed that while today more than 50% of frac treatments in the Bakken play use the OHMS technique, the use of OHMS is considerably less in other plays. Many operators believe OHMS carries an unacceptably high element of risk. If the operator cannot get to total depth with the completion, the completion must be laid down so a reamer or cleanout trip can be made. This can be problematic if swellable packers are involved because they can be activated and cause difficulties in round-tripping the completion. The alternative, if the completion is not too far off depth, would be to land the completion where it is and proceed to treat the well at less-than-optimum depths. Another more disturbing risk can crop up during the treatment. If pumping monitors indicate that a change should be made in stage depth, it cannot be made with OHMS. The intervals are preset when the completion string is run. In addition, enlarged boreholes and washouts in the laterals, often caused by drilling methods, increase the risk that the external isolation media will not seal completely.

Another overriding issue that can affect an operator’s decision on which technique to choose is the critical shortage of frac crews and equipment, especially in North America. Getting a frac date from a service company is much easier if the crew is needed for only a few days. It is exceedingly difficult to get a frac crew contracted for a week or more. This problem is likely to lessen in coming months, but presently it puts pressure on operators to choose expedience over a systematic approach, even if the systematic approach offers greater flexibility.

Adding to the complexity of either choice is whether water and proppant material are available. Lack of these can bring operations to a halt with disastrous consequences. The service industry is working to mitigate shortages of both, and results vary according to the geographic location of the play.

The inherent flexibility of PNP would seem to run second to the higher efficiency of OHMS, but technology has played a major role in leveling the playing field. The development of microseismic fracture mapping allows operators to monitor fracture propagation in real time, and the introduction of dissolvable diverters allows engineers to steer the fractures away from geohazards and offset wells. The main benefit of PNP is its ability to use real-time fracture mapping to make changes on the fly and thus place fractures where they are wanted, extend them as deeply as desired, and avoid geohazards such as aquifers that can instantly turn a potential oil or gas well into a water well.

In more mature plays, such as the famous Barnett shale of North Texas, refracs have become popular. Some wells are on their fourth refrac. This technique, which can restore new life into a declining producer, cannot be implemented with OHMS. The recently introduced Simul-Frac and Zipper Frac techniques show great promise and play to the PNP camp. These techniques involve alternating between stages on two or more adjacent wells, holding opposing stages in offset wells under pressure while treating the opposing stage in the well being fractured. Doing this creates a protective stress field around the pressured-up stages and diverts the fracture in the well being treated so the fractures do not intersect. Good coordination between the pumping crew and perforating crew is required, and results so far have shown that the practice has merit. It also mitigates some of the inefficiency of the PNP technique because multiple wells can be treated on the same trip to the field.

When asked to estimate the fraction of wells in each play that were PNP candidates for technical reasons (meaning that they cannot be completed using OHMS), respondents had strong opinions. Note the low frequency in Bakken and high frequency in Haynesville.

Diverse opinions in the field

Survey responses to the pros and cons of the OHMS vs. PNP techniques are tabulated in Tables 2 and 3. A total of 56 of the 116 survey participants expressed an opinion and 53 opted not to respond to the OHMS true/false questions. This lack of response may indicate inexperience in multistage stimulation completions or a market segment that has not yet formed an opinion on these issues. The key unresolved question is whether saving frac time and cost with OHMS is more valuable to operators than potentially improving well performance from the flexible but higher cost PNP.

Stated another way, one might ask, “Is it preferable to use a technique that has proved itself to be highly efficient when it works or to use one that almost always works, and may improve EUR of hydrocarbons over the life of the well? Which technique – OHMS or PNP – poses the greater risk, or which technique promises the greater potential reward?”

Each procedure has its champions, but overall the PNP technique is the most popular, its inherent inefficiencies notwithstanding. Even with clear acknowledgement of the speed with which OHMS treatments can be implemented, in a significant number of areas, the complexity and potential for problems has tempered enthusiasm for the technique. Less clear is the acceptance of a potential advantage of one technique over the other in terms of productivity potential where the number of respondents choosing true, false, or no opinion was almost equal.

A clear bias for OHMS in oil plays such as the Bakken was noted, most likely because significant financial advantages can be obtained by shortening time-to-market of a high-priced commodity and because the relatively higher upfront cost of OHMS completions can be justified in a play based on oil economics. The opposite is true in shale gas plays where the opportunity to optimize ultimate production influences operators to choose PNP completions.

A recently completed benchmark study compared decline curves from the five major shale gas plays. In each case, initial production registered a sharp peak that rapidly declined to about 10% to 20% of the peak value but than flattened and showed potential to continue at that rate for 20 or more years. With the possibility of realizing sustained production for decades, some operators are taking every step possible to optimize their completions.

Looking into the crystal ball

Respondents were asked to forecast OHMS and PNP activity through 2016. Results were generally optimistic, with slightly more favoring OHMS. When asked to forecast activity over the next three years for each technique in plays where they had experience, respondents’ opinions were mixed. Almost as many reckoned the activity would decrease rather than increase. However, OHMS was definitely rated to gain traction in plays other than the Bakken where it is already well established. It is unknown how seriously these forecasts were influenced by present supply shortages.

Forecast for OHMS by play.

There is ample scientific evidence that completions can be optimized by careful attention to pretreatment planning and design, along with systematic implementation of stimulation procedures. A thorough understanding of formation geomechanics as well as geological heterogeneity and complexity should result in less risk and should reduce production uncertainties. It is also correct to say that not all wells suffer these risks and uncertainties. Accordingly, one can conclude that an optimum solution will be obtained when preplanning shows clearly which completion and stimulation technique is most appropriate for the well in question. This will allow an objective evaluation of OHMS vs. PNP under the prevailing logistical and crew availability conditions.

In any case, hydraulic fracturing technology development is ongoing. Innovations are being introduced that have the potential to swing opinion back and forth between methodologies, and a new approach could be just around the corner. Already there is talk about “smart sleeves” that eliminate the ball-size limitation and, if perfected, will allow almost unlimited stages to be treated on a single trip.

It is safe to say that the current shortages of field crews, equipment, proppant, and water ultimately will be resolved, so the effect these conditions have on today’s treatment decisions is temporary at best. Meanwhile, the competition between OHMS and PNP is far from over.

Forecast for PNP by play.