About Terra Slicing Technology (TST):
Q: For a vertical well what information do you require at the outset?
Ideally the more information we have the better to determine the viability and produce a work-over plan for the asset. Initially basic data can determine the feasibility of applying the TST procedure and if there is a basis for moving forward by investigating the potential application of TST on the asset. Basic well data, Location, formation type, historical and current production.
For a proper analysis detailed well logs should be provided which would include as much of the following information as possible. The more information provided, the more accurate the results and analysis.
- Basic well-bore and drilling summary. Just a summary.
- ALL logs. Specifically, we need the log section in the producing formation + 1-200 feet above and below the formation and we need each log header and footer, including the part that shows units of measurement.
- Water analysis. We need salts mineralization and electro-conductivity of the water. We will use this information to re-calibrate the logs ourselves.
- Rock analysis. Again, we will use this information to re-calibrate the logs ourselves.
- Completion information and any subsequent completions. We need to know the details. Like if the well was perforated, how many perforations per foot, at what depth, what kind of gun, etc. If the well was fraced, I need to know breakdown pressure, treatment pressure, amount of sand, rate of water injection, chemicals used. If acid treatment was used, then acid type, concentration, volume, etc.
- Production data on the well. We would like daily or monthly production, plus all time the well is non-functional (down time), from the beginning. Knowing down time is just as important as up time, for calculations. We are interested in all fluids, oil and water and gas if any.
- Information on the "family" of wells surrounding this well. If you provide this same information 1-6 above, on the 4-6 nearest wells to the subject well, this helps us understand similarities and differences of the neighborhood. We will be able to draw an isopach map. We will be able to calculate the reservoir size, remaining oil, and changes in porosity, permeability, tectonic stresses, from well to well, over a wider area. Many other important conclusions can be made.
Q: Is the technology applicable to any kind of formation?
Yes. The technology can be used on any formation. Competitively speaking, the best formation is one that is tight, over-pressured / high-pressure, containing low-grade / high-viscosity / heavy oil, or one that is delicate / susceptible to over-balanced drilling / unable to be fractured / special issues. The only type of formation in which we have had poor results is unconsolidated oil sand.
The technology can be used on any well. A perfect well is one that is irreparably damaged at the target interval(s), and especially a well where another treatment(s) has been tried unsuccessfully. Second type of well includes mature, depleted, or declining production/injection wells in a field wherein there is justification to drill nearby new or infill wells. The only type of well we have had poor results in is a well that has watered out (mature water-drive well where well no longer has access to oil/gas above the oil/gas-water contact level). We will not work on wells that have unconsolidated sand.
Q: Is TST for depleted reservoirs or also for damaged ones?
The technology can and should be used in most cases on both types of reservoirs.
Q: Can TST be applied in new wells to replace conventional methods?
Absolutely, this is the recommended solution.
TST as it relates to fracturing and other enhancements:
Q: What is the difference between TST and Fracturing?
TST is not fracturing. TST uses high pressure water jetting/cutting technology to CUT and excavate an area within the target region. TST is often used as an alternative where fracturing is not an option or as a precursor to fracturing in order to better control and enhance the fracturing procedure.
Q: How does the additional production value that terra slicing brings (when used for production enhancement operations) compare with that of the hydraulic fracturing?
- Terra Slicing (TS) and Hydraulic fracturing (HF) have similar production profiles.
- TS has a longer term effect on the rock than HF. TS Slices stay open and active channels longer than HF fracture paths stay open and active.
- TS cleans up the well by washing the silts and other mobilized fines up-hole. HF does not. This directly affects production.
- TS removes rock from the formation which increases permeability. HF does not. This directly affects production.
- Decline curve for TS is shallower than for HF.
- Little difference in flush production between the two technologies exists.
- We have huge experience in well intervention of old wells. We increase production rate to 80% of original IP & often extract additional 100% of the cumulative production. HF cannot do this.
- Recent job. Perforation + frac = IP of 14 mcf, cumulative of 20,000 mcf over well life of 20 years. 5 years later, Operator used 2nd fracture that did not give any additional result. We intervened in same zone of same well. TS + frac = IP of 135 mcf, cumulative of 18,130 mcf over 2 YEARS!
Q: Technically speaking, how would a hydraulic frac job compare to a Terra Slicing job?
- TS typically excavates almost as much rock by weight as the typical hydraulic fracture (HF) injects.
- HF imposes pressure against the rock equal to the breakdown pressure until it cracks; TS imposes no pressure against the formation but instead releases the pressure back up the annulus. TS maintains hydrostatic pressure < formation pressure.
- HF can be implemented quite fast – 20 or 30 minutes – not including perforation, set up, rig down, or blow-back. TS is slower – hours, to 1 day or more depending on height of formation. Cutting requires more time than cracking.
- HF uses many chemicals in great amount. TS uses minimal to no chemicals – typically formation brine only.
Q: What are the main differences between polymer flooding or gas injection compared to the TS process?
Water or polymer flooding, and steam or gas injection are different from TerraSlicing in their purpose and implementation. They are not mutually exclusive and you can use all of them on your well. For efficiency you should use TerraSlicing first.
Now, we can give a general overview of these alternatives, but the overview will be as broad as the array of water-jetting technologies out there. To be really precise we would need to know more about them.
Flooding and injection are used to keep the reservoir pressure higher or more stable than it would be after extracting petroleum (as fluids are extracted, pressure normally goes down).
Flooding is used in pressure-drive or solution-drive reservoirs to replace the petroleum / natural gas fluids that have been extracted from the formation in order to keep pressure high or at least stable. As the oil rises to the top of the formation, the flooding is introduced at the bottom. Water flooding and miscible gas injection are common examples of this EOR.
Polymer flooding is more expensive, but additionally provides a solution to prevent problematic mobilization of water or certain oil by-products like paraffins, asphaltenes, or silt/sand.
Steam injection is used for heavy oil formations. The introduction of extreme heat from the steam causes the heavy oil to flow more easily to the surface. The same method can be used to raise the pour point and loosen up paraffins and asphaltenes to unclog the formation and extract these by-products to the surface.
Gas "injection" and gas "lifting" are slightly different. Lifting is limited to injection to the well-bore only, and not the reservoir. Gas lift replaces rod pumping.
These methods do not achieve the 15 benefits that terra-slicing achieves, found on the back of our brochure and on this page here.
Pressure related questions:
Q: What is the maximum pressure on surface.
There are 3 different pressure regimes:
1) Testing pressure is 7500 psi for 1 minute.
2) Working pressure is 5000 psi for the entire job.
3) Special case pressure is 6000 psi.
Q: What is the max surface pressure required to be able to cut multiple casing strings at say ~ 15,000 ft?
Typically 5000 psi is the maximum surface pressure required and in special cases 6000 psi.
Q: How about the effect on the DP's and surface equipment from the erosion of the DP's.
No impact on DP’s or surface equipment. There are two main reasons for this.
- Maximum working pressure at surface of 5000 psi never exceeds burst pressure.
- Generally abrasives must impact a material to be cut at an angle to cause erosion. When abrasives flow down the drill or tubing string to the DHA, the abrasives more or less flow in a path parallel to the drill string or CT. This leads to little or no erosion.
- Generally TerraSlicingTM does not use harsh corrosive chemicals.
Q: How can we assure this pressure will not be exposed to the formation?
Formation pressure must always exceed hydrostatic head so no hydraulic pressure can ever be applied against formation. High working pressure in DP or tubing is converted to exit velocity at nozzles used in the cutting process, thus there is never exposure or application of hydraulic pressure against formation. As a result, the formation is always exposed to under-balanced pressure.
Q: How we are filling the DP's while RIH and how we can establish circulation while RIH if need it or in case of well control issue.
TerraSlicingTM BHA is designed for flow and reverse flow at various pressures and follows industry standard circulation procedure. The equipment is designed on two principles:
1) The equipment has standard API “thru-tubing” design
2) The equipment is not live (operating) during RIH and POOH.
Q: Will 5000 PSI be the maximum required pressure ratings of the pumps or more pressure could/will be required?
Practically speaking, 5000 PSI is the maximum. At the beginning of the procedure, we conduct a safety pressure test wherein we raise pressure to 1.5x the working pressure, but below the burst pressure of the work string, for one minute, to test for safety purposes. Generally, we use 4000-5500 psi working pressures. The highest commercial job we have been involved in is 7000 psi, but technology is capable of pressures up to 10,000 psi.
Cutting and excavating related questions:
Q: Can a slice be cut with a certain dipping ( i.e. parallel to formation dipping) at a certain angle?
Generally TerraSlicingTM can be oriented in any direction. In some wells if this means that dipping = “azimuth”, then the answer is yes, the slice can be cut with a certain dipping. Without optional services, the TerraSlicing machine is limited to orientation whereby one plane is parallel to the well-bore direction at all times.
Q: How you control the depth of cut?
There are two different ways to control the depth of cut: Design and Calibration.
Design: Nozzle parametrics determine the focus and shape of slice. We have various nozzles from which most appropriate nozzle is selected as part of our work over plan.
Calibration: The equipment is per-calibrated before it is lowered into the well with the parameters of the planned slice. The equipment cannot cut beyond the set parameters.
The operator adjusts cutting speed, abrasive concentration, working pressure, and fluid rate to ensure that the slice is proceeding as planned and confirms the slice with real-time reports.
Q: Does TST have the ability of making 2 sets in one run at different depth?
Yes, the tool can make two sets of cuts at different depths. Terra Slicing of multiple intervals is achieved by:
- The tool is calibrated, as indicated in question 1, for multiple cut parameters.
- The tool is positioned at the deepest interval first.
- Tool is moved upward to the next position.
Q: Regarding the slurry used to do the excavation, will it be brought up to surface or remain in the formation. If up to the service, how will it be done?
All slurry returns to surface. Slurry travels down to target interval through tubing, CT, or drill pipe. Slurry cuts window in casing, cement, and formation. Window shape has x, y, and z planes. Cuttings and slurry returns back up to surface through annulus. Pressure in the formation is determined before beginning of operation. Operation is planned so that formation pressure always exceeds hydrostatic pressure in annulus. So, absolutely no slurry is injected at any point into formation, and no cuttings can stay in formation.
Q: How are the cuttings and excavated material brought to surface?
Cuttings always return to surface. For example in a 5-inch well-bore (we can use any casing size as long as it exceeds 4 inches ID), the speed of the returning slurry is approximately 25-28 mph or 40-45 km/h.
For cuttings to stay in hole, the downward force of cuttings must exceed the upward force of slurry returning to surface. Slurry travels upwards at 40-45 km/h in annulus. Opposing or downward force of the cuttings cannot resist the force of the returning slurry. Gravity = 8 m/s x 60 sec. x 60 min x 0.1 gram = 28.8 km/h. The cuttings travel to the surface at the net rate of 15-18 km/h and get dumped in filtration and pit. If there is a concern that casing size is too big (fear that cuttings will not rise), or for formations is too high porosity (fear that formation will absorb fluid), N2 foam can be added to slurry to make hydrostatic even lighter. This is all per-calculated.
Production and implementation related questions:
Q: What is the correlation tool (Gyro, MWD, etc.)?
The tool uses gyro with telemetry.
Q: Due you need special connection for the BHA?
No. The tool uses Standard API connection.
Q: How we can cure the losses if any (is there any limitation for LCM)?
No limitation for loss control management (LCM). Terra Slicing uses an under-balanced drilling apparatus and LCM procedures are industry standard. Losses into formation would not occur:
- Terra Seal of Casing; in this situation formation is not exposed.
- Terra Slicing for Production Improvement; in this situation the formation is exposed; however formation pressure must always exceed hydrostatic pressure.
Q: Does TST need a rig to do the job or a coiled tubing unit is enough and acceptable?
Either a work over rig or coiled tubing rig will work.
Q: How will the tool be operated? Hydraulically, Mechanically etc.
Cutting function and well-bore anchors operate hydraulically. Positioning and data transfer operate electronically and mechanically. Remainder of machine operates mechanically.
Q: What are the available tools sizes?
The minimum size of 4 inches/102 millimeters is the minimum requirement for the inside diameter of the casing. No maximum.
Q: Can the service be run via wire-line or slick-line?
No as a matter of fact that there is pumping while doing the service. It can be done via drill pipe or coiled tubing only. We must pump slurry though drill pipe (API 2-3/8 inch OD minimum), production tubing (J-55,API 2-3/8 inch OD minimum), or coiled tubing (2-inch minimum) - CT injector head must exceed 3.875-inch minimum.
Q: After doing the excavation, how will it be guaranteed that the formation will not collapse?
The terra-slice is designed before the operation. The forces causing rock collapse (function of formation pressure and rock strength) < (are less than) forces keeping terra-slice window open. Terra-slice forces are > (are greater than) minimum window size necessary for pressure unloading. It is all per-calculated. The window size is calculated to be strong enough to resist closure from total forces of formation stresses, and strong enough to unload well-bore stress in near-well-bore zone. The unnatural terra-slice shape stays open for this reason. In high-pressure or softer rock formations, the window slice is much smaller than in low-pressure or harder formations. If there is concern, or for per-caution, we can fill the window cavity or void with resin-coated sand (RCS) but usually this step is not necessary.
Q: What is the typical procedure, process, or method for a TST application?
Typically a TST application includes the following: necessary analysis, planning, design modifications, calibrations, application of TST for excavation and cutting of the designated interval, qualified supervision of the TerraSlicingTM tool and application.
Q: What information is required by TST to evaluate the Job?
The more information that can be provided on the well, the better and faster the TST team can evaluate the job and provide an effective quote, and cost/benefit analysis. Ideally we will require the well logs in order to accurately analyze the project. Any data on surrounding wells, or at least well history on production and formation would be acceptable is a preliminary analysis.
Q: What about 3rd party costs?
Third party costs are typically not covered by TST. TST application does not include costs for surface equipment, rig charges, abrasives, fluids and charges beyond the provision of Terra SlicingTM tool. Arrangements may be made to price third party costs as part of a mobilization fee and incorporated into an overall quotation for convenience to the client. Costing and pricing are all negotiated to the specific job and application.
Q: What pricing components are involved in a TST application?
While each job is customized by its application, time, and difficulty, the application of TST to a given asset for well enhancement (Terra Slicing) typically has an up-front and mobilization fee related to the cost of service and a Royalty component ongoing for well production.
In the event we are applying TST for a non-enhancement procedure such as Terra Seal (for plugging or abandonment of a well asset) a price would be negotiated based on the service done.
Q: Why does FalconRidge charge a royalty on enhancement procedures involving TST?
FalconRidge enhances a given property to for greater production and profitability using its proprietary technology and expertise (TST). The net result is a far greater revenue stream and profitability to its working partners. As a result FalconRidge is generally granted a royalty of production for its enhancement services. This is usually on a “bonus” type arrangement on the enhancement, an ongoing Royalty basis on production, or a combination of the two. The simple answer is a client realizes a far greater revenue using TST than without.
Q: What is the minimum time to mobilize the tools?
We can typically mobilize and be on site within one week once final documents are signed and third-party equipment is scheduled. This of course must also take into consideration geographical location, any local regulatory requirements in the operational jurisdiction, and climate.
Q: What are the advantages of the Terra-Seal process?
- Well can continue to operate – no need to P&A, no need to sidetrack, no need to re-enter.
- Stabilizes against corrosion and mechanical stresses in interval (from acid stimulation or salinity)
- Innermost casing maintains hydraulic integrity (procedure does not rip up the casing)
- You can run a API drift casing gauge after the procedure to observe the smooth cuts
- The 30” conductor casing at surface will be far more stable (no shifting back and forth)
- Eventually, on P&A, the casing (no longer leaking) will not need to be pulled
- Safe for environment and workplace procedure
- Minimize downtime (~1 day per interval)