Horizontal Underbalanced Drilling of Gas Wells with Coiled Tubing
- R.J. Cox (Fracmaster Ltd.) | Jeff Li (Fracmaster Ltd.) | G.S. Lupick (Fracmaster Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 1999
- Document Type
- Journal Paper
- 3 - 10
- 1999. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 1.8 Formation Damage, 4.2.3 Materials and Corrosion, 1.6.6 Directional Drilling, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.7 Pressure Management, 1.12.6 Drilling Data Management and Standards, 1.10 Drilling Equipment, 5.2 Reservoir Fluid Dynamics, 1.6.1 Drilling Operation Management, 1.7.1 Underbalanced Drilling, 1.7.5 Well Control, 1.7.7 Cuttings Transport, 1.11 Drilling Fluids and Materials, 1.5 Drill Bits, 4.6 Natural Gas, 5.3.2 Multiphase Flow, 3.2.2 Downhole intervention and remediation (including wireline and coiled tubing), 1.6 Drilling Operations, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.2 Separation and Treating
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Coiled tubing drilling technology is gaining popularity and momentum as a significant and reliable method of drilling horizontal underbalanced wells. It is quickly moving into new frontiers. To this point, most efforts in the Western Canadian Basin have been focused towards sweet oil reservoirs in the 900-1300 m true vertical depth (TVD) range, however there is an ever-increasing interest in deeper and gas-producing formations. Fig. 1 shows a composite vertical section of the horizontal or directional underbalanced wells drilled with coiled tubing in Canada, and also highlights the aforementioned trend towards oil over gas. Significant design challenges on both conventional and coiled tubing drilling operations are imposed when attempting to drill these formations underbalanced.
Coiled tubing is an ideal technology for underbalanced drilling due to its absence of drillstring connections resulting in continuous underbalanced capabilities. This also makes it suitable for sour well drilling and live well intervention without the risk of surface releases of reservoir gas. Through the use of pressure deployment procedures it is possible to complete the drilling operation without need to kill the well, thereby maintaining underbalanced conditions right through to the production phase. The use of coiled tubing also provides a means for continuous wireline communication with downhole steering, logging and pressure recording devices.
Coiled Tubing Equipment
Coiled tubing drilling rigs currently exist in several different forms and setups, but generally consist of a drilling coil, injector to feed the tubing into or out of the well, (blowout prevention) (BOP) system for well control and return fluid path, and a control cab and power unit. The coiled tubing drilling equipment used to drill the case studies presented later in this paper consisted of either 60.3 or 73.0 mm coiled tubing and injector with a hydraulic power unit with control cabin and accumulator. A coiled tubing hybrid mast unit and substructure complete with V-door and catwalk was used. Pumping equipment included a fluid pumper capable of liquid rates of 0.10-1.5 m3/min, nitrogen pumper capable of 10-120 m3/min, and a nitrogen bulk storage unit of 50,000 m3 capacity. When drilling sour gas formations, a chemical injection pump for corrosion inhibition is typically used.
Of the two coils commonly available, 73.0 mm is the preferred size due to its added weight on bit, stiffness, increased annular velocity and decreased pump pressure compared to the 60.3 mm coil. However, to remain transportable under local highway size and weight restrictions, length of 73.0 mm coil is limited to approximately 3400 m of useable coil. Wells deeper than 3400 m measured depth (MD), or alternatively those requiring drilling through 114.3-mm casings would require use of the 60.3-mm tubing, with a depth restriction more in the order of 4200 mMD.
The bottomhole assembly (BHA) used to drill the case study wells is shown in Fig. 2. It consists of a drill bit, positive displacement mud motor with surface-adjustable bent housing, and nonmagnetic dual float sub. A gamma ray tool and steering tool are housed in a nonmagnetic collar complete with rubber inserts for vibrational resistance. A downhole pressure sub, nonmagnetic collars (as required for nonmagnetic spacing), coiled tubing quick connect, bi-directional orienting tool and coiled tubing connector then complete the assembly. The coil is fitted internally with a seven-line multiconductor wireline for steering tool, gamma ray tool, and pressure sub operation. Two steel capillary tubes for hydraulic operation of the orienting tool are also packed within the coil. Survey data (inclination and azimuth) and annular pressure, and gamma ray are recorded real-time approximately 10 and 11 m back from the bit, respectively.
Vertical extension drilling of gas wells where only 5-10 m of formation are drilled out commonly occurs with straight nitrogen or air, and therefore flowing back through a blooie line to a flare pit is common. The short length and duration of these operations typically do not require significant volumes of liquid to be pumped for motor lubrication. Horizontal gas wells, by contrast, are typically drilled with significant volumes of liquid for motor lubrication, performance, motor life, and improved hole cleaning capabilities. For this reason, a blooie line or flare pit is seldom acceptable and the surface handling system typically includes an 80-m3 test separator complete with choke manifold, sample catcher and flare stack, as well as 64-m3 upright tanks for drilling fluid storage. The presence of a separator vessel precludes the use of air as a drilling medium, so nitrogen is normally used for horizontal gas wells. Flowback is maintained within a closed system except for the flarestack, and the operation is sump-less so environmental impacts are minimized. Equipment requirements for underbalanced gas drilling are therefore essentially the same as for underbalanced oil well drilling, and Fig. 3 shows a typical lease layout.
Blowout Prevention Equipment
The typical BOP stack used for drilling the gas wells presented in the case studies is shown in Fig. 4. Of specific interest is the lubricator and packoff which allows a portion of, or in some cases, all of the bottomhole assembly to be lubricated or stripped out of the hole without interrupting the flow of the well. The packoff assembly replaces the rotating BOP as used with conventional underbalanced wells, and the use of a wireline and lubricator allows the assembly to be lubricated or deployed out of the hole while flowing the well. A master valve at the base of the BOP stack is recommended for gas wells as this allows the well to be shut-in at surface to remove the BOP equipment without killing the well. Alternative procedures include snubbing a bridge plug into the casing to shut-in the well and facilitate both installation and removal of the BOP stack.
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