Michael Tulissi: International Technical Director for Fracturing Services with Trican Well Service
Andrey Smarovozov: Director, Pressure Pumping, Russia & Caspian (Marketing and BD), Baker Hughes
Kevin Mullen: Senior Production Stimulation Engineer for Schlumberger-Russia
Igor Kuvshinov: Senior Technical Leader, Halliburton Company
What are the most important aspects to consider when designing and implementing a frac job?
Michael Tulissi: It is most important to consider the desired fracture geometry and conductivity, as well as the optimum economic yield. The design will be dependent on accurate data concerning formation permeability and pressure, a clear understanding of rock mechanical properties that affect the created geometry, and current well conditions such as damaged and undamaged reservoir parameters.
The design must strive to eliminate failures and include an understanding of the fracture cleanup process, as well as the relationship between propped fracture length and the effective producing fracture length that are, in practice, very different. To this end, experienced operators, comprehensive Quality Control and reliable equipment are essential.
Andrey Smarovozov: When designing, the most critical aspects for accurate Frac design would be well readiness (ie casing and cement condition), formation data, including rock properties, formation and fluids parameters. Having the reliable data would significantly increase the accuracy of the design, thus optimizing the individual treatment for the specific well. While executing a frac job, the most critical areas would be QA/QC control and the flexibility within the chemical additive system with each parameter being closely controlled. Saying that, I mean, that what’s stated from the prospective of the desirable result must be executed the way it was planned. The equipment should be flexible to allow varying each of the individual components to keep the fluid system optimal and at minimal cost.
Kevin Mullen: A frac treatment design should be as individual as one person is to another. The most crucial element of designing a job is to take all well characteristics into consideration while determining the optimal geometry for that specific well to optimize production. This includes determination of where the fracture should be placed, to what extents the frac can grow, and how much proppant is required for adequate conductivity. A simple example is designing a frac that is large enough (by mass and width) to produce effectively, but small enough (by shape and volume) to avoid stimulation of nearby water layers.
Igor Kuvshinov: Having a sufficient amount of basic knowledge of the rock and reservoir properties allows you to solve the fracture geometry, general speaking. Some Operators readily accept this and do not want to go beyond this basic level. However only a detailed analysis of the data regarding the rock mechanics, reservoir fluid and PVT data allows you to solve the question whether the selected fractured completion will have sufficient long-term conductivity to produce the reservoir to the targeted degree. The wisest option for the Operator is to select the full analysis approach because of the increased return in the mid to long term.
Formation damage is one of the greatest dangers during a frac. How can you minimize the risk of formation damage during the job?
Michael Tulissi: Fracture treatments can result in two types of damage: damage to the formation itself and damage to the conductivity of the proppant within the fracture. Formation damage can be mitigated by proper compatibility testing of frac fluid/additives with formation rock and fluids, as well investigating suspected damage from previous treatments. Damage to the proppant conductivity can be minimized by reducing the amount of polymer based gel, using improved breaker technology, better post fracture clean-up procedures and the inclusion of nitrogen in fracturing fluids.
Andrey Smarovozov: There are several ways of minimizing fracturing fluid formation damage factor, (as well as a proper stress proppant application is a must):
1. Low polymer loading systems (such as BJS’s QuadraFracТМ which allows us to decrease polymer loading down to 18-20 ppg from 30-35ppg system) with similar proppant carrying capacities.
2. Application of polymer-specific enzyme breakers (this allows to the increase of frac gel break of up to 98% as opposed to an average of 30-40% in a normal guar-borate system with oxidizers as a breaker)
3. Polymer-free frac fluids, which contain no polymer make “filter cake” fracture damage theoretically impossible. Chemical processes of formations being affected by water should not be left out of consideration either and should be closely controlled.
4. Foamed fracturing fluids allow you to reduce the total amount of polymer left in the fracture, simultaneously helping the process of well clean-up and kick-off. However, since the volume of guar-borate fluid is reduced in foam (the remaining is nitrogen), maximum effective concentration of proppant in a fracture volume is limited.
Kevin Mullen: Formation damage can be extremely detrimental to well production, but these problems can be easily managed by proper pre-treatment analysis and design of the breaker package to degrade the frac fluid. To avoid any potentially irreversible problems, it is strongly recommended to test in the laboratory the interaction of formation fluids (oil and water), the fracture treatment fluid, and even wellbore fluids (such as work-over brine). If incompatibilities are observed, then the treatment fluid recipe must be adjusted with inhibitors to impede those effects. Testing against formation rock may not be practical, so a clay stabilizer should always be present in the recipe. Finally, an aggressive breaker package must be tested and included in the fluid design to minimize residual damage.
Igor Kuvshinov: The ability to provide best-in-class stimulation treatments comes not only from the total horsepower in delivering proppants downhole, but from an educated knowledge of the overall picture, allowing you anticipate problems and successfully engineer ways around them in order to target long-term fracture conductivity.
The best way to minimize the risk of damage during the job is to design a fracture target conductivity based on all relevant data, while tailoring frac fluid and ensuring complete frac clean out shortly after the well is in production. Knowledgeable service companies work over every aspect influencing the conductivity of the final fracture, including chemicals, materials, placement techniques, etc. in order to ensure success.
Do you have any new technologies which are being deployed in the Russian oilfield?
Michael Tulissi: Trican is a technical leader in the pressure pumping industry and customers worldwide are benefiting from these innovations. In Russia, these include:
» Multistage Frac System (Selective fracturing of horizontal wellbores)
» IsoJet (Selective fracturing using jet perforation through coiled tubing)*
» DRA-2 (Delayed Release Acid Breaker)
» WCA-1 (Relative Permeability Modifier for water conformance)
» SI-3 (Scale inhibitor pumped during fracturing operations to reduce scale build up and pump damage due to deposits)
» Stratum Frac (Ultra low polymer fracture fluid providing superior shear stability and proppant carrying capacity)*
» PropLock (Proppant Flowback control)
» Various fracturing fluids including Nitrogen
These products were developed in Russia to address local requirements.
Andrey Smarovozov: With BJ being part of Baker Hughes now, the following technologies of theirs are planned for use in Russia:
» QuadraFracТМ low polymer loading system is going through field trial tests.
» Polymer-specific HPHT enzyme breakers can be widely implemented.
» Polymer free frac fluid system – AquaStarТМ (surfactants system) was delivered to the country and is planned for a field trial.
Kevin Mullen: As one of our core values, Schlumberger understands the value and importance of technology. And we are exceedingly proud of the manpower and funding we annually put into research. In Russia, at different points over the last 6 years, we’ve brought several frac technologies including FiberFRAC*, foamed frac fluids, and AbrasiFRAC*; these focus on frac geometry and operational efficiency. In the next few years, as multi-stage fracturing in horizontal wellbores gains in popularity, StageFRAC* will become a more common fixture in the market. But we are most excited by a revolutionary new technology coming soon! Look for HiWAY* to be rolled out this fall season!
Igor Kuvshinov: Halliburton’s Pin-Point Stimulation group of technologies for multi-stage fracturing combine well with known technologies such as hydra-jet perforating, fracturing and coil tubing to achieve precision placement with full fracturing technologies that significantly reduced completion time. Some of these technologies (CobraMax, Surgifrac and DeltaStim Completion) have been deployed in the Russian oilfields since 2004. Waterfracturing is incorporated as one of efficient proppant placement technologies but has not been deployed in Russia operations yet. In order to promote long-term conductivity and reduce proppant diagenesis phenomena, Conductivity Endurance and Monoprop technologies can be deployed.
To what extent are open hole multi-stage frac jobs being carried out in Russia?
Michael Tulissi: Though still in developmental stages in Russia, the application of open hole multi-stage frac technology will certainly increase as horizontal well lengths increase, and the average permeability of the targeted formations decreases. In these cases, the technology will also improve the economic advantage of horizontal wells relative to traditional vertical completions. Trican has extensive experience in open hole multi-stage fracturing and is prepared to expand operations of this nature into each of its geographic regions.
Andrey Smarovozov: Several common technologies for open hole multi fracturing were tested as field trials. The technologies are more or less similar and are represented, for instance by: BJS (DirectStimТМ), Baker Hughes (Frac-PointТМ).
Kevin Mullen: This completion method has yet to take firm root in Russia at this point, but there has been significant interest in the technique of late. Several operating companies are just beginning to trial multi-stage fracturing, and I suspect that others are eager to follow. The trick behind this technique is to effectively segment off the horizontal section to allow for control over the fracture initiation point. Current completion strategy in Russia (commonly slotted liners) does not allow for control over frac placement. So in order for multi-stage fracturing to take off, completion designs will need to be altered significantly.
Igor Kuvshinov: The application of open hole multi stage frac operations are still in their infancy in Russia. However there is a growing interest among the major producers to open hole multi stage frac technology. You could reflect that the reason for this is that growing demand is making low permeability assets profitable. Several of the above mentioned technologies have been trialed and accepted for wider implementation.
Post frac analysis can readily identify whether the frac job has been a success. What is the level of uptake of post analysis in the region? (What would need to change in order to improve this?)
Michael Tulissi: Post frac analysis is performed to evaluate a treatment and help design the next one. It refers to the analysis of the fracture treating pressure and the obtained production rate, and are both performed routinely. However, this method can be unreliable as the results are not unique. More accurate analyses, such as flow and build up or pressure transient analysis, are performed quite infrequently. These latter tests are time consuming and require an interruption of the wells production, making them less desirable. To improve broad acceptance of post frac analysis, a desire to design, execute and evaluate fracturing treatments in a holistic way rather than as independent processes is required.
Andrey Smarovozov: One of the objective factors of a successful frac operation is a post-frac production and its match with the designed pos-frac production rate. Although all the largest Operators in Russia conduct post-frac analysis (and in some special cases it’s actually a must) the extent of post fracture analysis could have and should have been larger. Further more, to improve and optimize a frac job a data frac is conducted prior to the main frac treatment with post data frac analysis on location followed by the main frac schedule adjustment.
Kevin Mullen: It is Schlumberger’s policy here in Russia to make an individual post-frac analysis on 100% of wells in which we perform a propped fracturing treatment. We do net pressure matching to validate the fracture geometry which we’ve created, and together with the pre-treatment calibration test data, we’re able to improve upon our fluid and rock modeling in subsequent job designs. Pressure matching does provide a reasonably good assessment of actual fracture geometry, but the accuracy can be improved through analysis of either bottom-hole pressure data or by direct measurement of fracture height using our SonFracMap* service.
Igor Kuvshinov: Post frac analysis in Russia is not yet receiving sufficient attention yet. Despite of significant advances in region in achieving understanding of fracture geometry the improvement is needed. That is especially true for those companies who decide to make step change in understanding fracture geometry for purposes of generating efficient oilfield-wide reservoir fracture assisted drainage system, with the aim of maximizing hydrocarbon production.
With the above target in mind, it is very important to utilize the best available modeling practices to identify the response of the rocks and resulting geometry at an early stage of field development. The pressure matching approach that is currently used alone is not sufficient for throughout analysis. Pre-treatment specialized diagnostic pumping and microseizmic fracture mapping are well recognized techniques, and are mandatory for correct fracture geometry analysis. The long-term performance of fractures should be much easier to forecast when analysis is completed utilizing above data.
Waterfracturing is not being fully implemented in Russia as yet. As the region develops it’s shale gas reserves do you think this technology will be utlised in the region? What benefits will it bring over the current solutions?
Michael Tulissi: Waterfracturing is a low cost, virtually non-damaging method of fracturing wells where only low fracture conductivity is required. In the Russian region, few reservoirs are currently being developed with permeability that is low enough to benefit from waterfracturing. We expect that as very low permeability shale reservoirs begin to be exploited, this technology will become better utilized.
Andrey Smarovozov: That is correct, since CBM or tight gas formations are not being developed in Russia, slick water fracturing or fracturing with Light Weight Proppants application are not used in Russia for now. The benefits these technologies could bring would be minimized fracture surface damage with maximal reservoir fluids reserves being evolved into production. That means conventional type of fractures opening hydraulically additional reservoir areas at longer distances from wellbore with minimal residual formation damage.
Kevin Mullen: Different reservoirs require different characteristics for their hydraulic propped fracture. The shape and size of any propped frac is exclusively dependant on the fluid and rock properties of the reservoir. For the low-mid permeability oil formations typically targeted today, the current techniques are preferable. If exploiting shale reserves become prevalent, then high-rate water fracturing might also become more popular in Russia. But the main question that any operator and service company needs to first ask themselves before deciding is “what geometry can this technique provide, and how much does that directly affect the well’s production?”
Igor Kuvshinov: Waterfracturing could definitely improve results in shale development in Russia. Some of the major benefits of this technology would be the distribution of propping agents and the use of low-damaging fluid. The benefits could be more visible for gas reservoirs, however oil reservoirs will see improved production as well. This is however true for any new technology introduced.