Drilling & Production

Fracture geometry from the treatment well in real time

Fracture geometry from the treatment well in real time

A new fracture mapping service, which employs downhole tiltmeter technology to map fracture geometry from the treatment well in real time has been developed. The developers content that the technology can help operators know more precisely how their reservoir is responding to a fracture treatment, allowing for better-informed asset management decisions.

The FracTrac TW (Treatment Well) service is provided by Pinnacle Technologies through a service provider alliance with Halliburton. The developer claims that understanding fracture creation through direct, real-time measurement of fracture geometry, and using this information to more accurately calibrate the fracturing model, can help optimize the treatment of the producing zone and yield improved production.

Prior to this, an operator's only means to obtain direct information about fracture growth in real time was via fracture mapping from offset wells and/or the surface. While fracture imaging from offset wells is highly reliable, application is limited to areas where nearby offset observation wells can be utilized.

Surface monitoring is, at present, limited to onshore applications, only provides orientation measurements, and requires drilling several shallow holes around the treatment well.

Currently, most fracture treatments are preceded by a diagnostic injection procedure (actually a miniature fracturing treatment or minifrac) to evaluate the stress and permeability environment in the near wellbore area. This service is based on placing wireline-conveyed downhole tiltmeters in the treatment wellbore during the mini-frac treatment. The fracture mapping results (height and width) are then used to help calibrate the fracture modeling software on-site to allow treatment design optimization. Fracture mapping is appropriate in a wide variety of situations and is especially applicable when:

  • The fracture is being created in multiple, layered zones
  • During an active infill drilling program
  • When beginning a large fracturing project.

The developers say the technology can also provide an environmentally safe alternative for situations where radioactive tracers are not practical, and can help reduce the number of wells to be drilled by more accurately defining the fracture contact area.

System created for short radius under-balanced drilling

A new coiled tubing drilling (CTD) bottom hole assembly (BHA) that will drill short radius wells in an underbalanced condition vastly improves productivity. This innovation represents a major breakthrough, especially for contractors drilling for gas. Despite its apparent suitability, the typical CTD has not performed particularly well in the gas-drilling arena, primarily due to the harsh environment that exists within the wellbore.

Because nitrogen foams and light fluids don't provide effective damping, downhole tools are subjected to high vibrations and shocks generated by the drilling process, resulting in the low reliability exhibited by some earlier BHAs. The AnTech Colt by AnTech Ltd (Exeter, England), is designed to overcome these obstacles, and makes it possible to carry out short radius under-balanced CTD in a number of ways:

  • Measuring half of the length of conventional CTD assemblies, this BHA is much more responsive and can build angle with ease as it moves through the reservoir, the developers say. Drilling engineers are no longer constrained by the much longer unwieldy CTD assemblies that require them to drill much further, and for longer periods, to achieve the same results.
  • Control of the drill bit orientation is achieved with the use of an electrically driven orienter that can provide intermittent or continuous rotation. It is sized to allow rotation while drilling, avoiding lost time when changing direction and allowing both buildup section and straight hole to be drilled using the same tool.
  • To provide real-time feedback to the operator on downhole conditions, tool position and geological formation, this assembly is equipped with sensors that rely upon wireline telemetry to gather the data. Sensors include a pressure compensated weight-on-bit sensor and pressure sensors in addition to the steering and gamma ray sensors. This information is continually transmitted to the display panel at surface. The operator can then analyze this data to make informed drilling decisions, which will be critical to the success of the operation.
  • To ensure that the system is completely reliable and will withstand shock and vibration while operating downhole, the assembly offers several key features. The physical layout of the tool and its packaging is designed to be resistant to the damaging effects of drilling vibration.
  • In order to further bolster the ability to withstand the gas-drilling environment and prevent failures, it is fitted with durable metal-to-metal seals. The smooth flow-path also means that fluid-induced wear and vibrations minimally affect the tool.
  • With a compact size, the system is easy to rig-up, requiring just one connection to the coil and one connection to the drilling motor. The rig-up time at the wellhead is reduced to minutes.

New PDC cutter replaces conventional bit technology

A breakthrough in polycrystalline diamond compact (PDC) technology is yielding increases in wear resistance and rates of penetration (ROP), resulting in greater footage drilled, fewer bit changes, and reduced drilling costs. Field results from wells drilled using bits equipped with the new TReX cutters show ROP increases of more than 70% and drilled-section increases of more than 50%. These numbers reflect a comparison with results from wells drilled using the same bit types, but equipped with conventional cutters.

The new PDC material, patented by Schlum-berger, keeps cutters sharper without compromising toughness, the developer claims. Depending on the size mix of diamond grit, traditional cutters have been either more wear resistant or more impact resistant. In drill bit development, advancing one property has always limited the other. This cutter overcomes this compromise by providing an wear -resistant edge at the cutting surface, with no loss of impact properties. The cutters demonstrate 400% greater wear properties than standard PDC cutters and have equal impact properties. In the field, the developers say the cutter stays sharp as it wears.

In the North Sea, the cutters delivered an 89% increase in ROP and a 25% increase in footage drilled. Standard cutters on a 12 1/4-in. standard bit drilled a 1,450-ft interval through the Tor and Flounder formations with an ROP of 22 ft/hr. A 12 1/4-in. DS97 Reed-Hycalog bit with the cutters was used to drill a similar section in the Flounder and Herring formations, which included a demanding marl-limestone sequence. A 1,932-ft interval was drilled, and the ROP nearly doubled, at 41.5 ft/hr.

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