Relief-Well Requirements To Kill a High-Rate Gas Blowout From a Deepwater Reservoir (includes associated paper 19889 )
- Richard A. Warriner (Triton Engineering Services Co.) | T.G. Cassity (Triton Engineering Services Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1988
- Document Type
- Journal Paper
- 1,602 - 1,608
- 1988. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.3.2 Multiphase Flow, 1.7 Pressure Management, 2 Well Completion, 1.6 Drilling Operations, 4.1.2 Separation and Treating, 1.8 Formation Damage, 1.6.6 Directional Drilling, 3 Production and Well Operations, 1.7.5 Well Control, 1.10 Drilling Equipment, 4.1.5 Processing Equipment, 2.7.1 Completion Fluids, 1.11 Drilling Fluids and Materials, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.1 Well Planning, 4.2.4 Risers, 5.2.1 Phase Behavior and PVT Measurements, 5.1.1 Exploration, Development, Structural Geology
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Summary. Relief-well requirements were investigated for a dynamic kill of a high-rate gas blowout from a deepwater reservoir to define any necessary special procedures or equipment. Results of the investigation show that a high injection rate and a special-design large-diameter injection riser are required to dynamically kill such a blowout with seawater. The injection riser is necessary to limit surface pump pressure during the high-rate kill operation. Procedures to complete the killing operation hydrostatically with heavy fluid following the dynamic kill are outlined.
Over the past several years, a number of wells have been drilled in deepwater gas reservoirs to provide test data on high flow rate reservoir performance. Casing programs for these wells are designed specifically to enhance the ability to produce at high rates. Typically, 13 3/8 -in. [34-cm]casing is set just above the reservoir and a 12 1/4 -in. [31 -cm] hole is drilled through the productive interval. The probability of a blowout occurring while drilling and completing, one of these wells is small. The difficulties associated with con-trolling such a blowout, however, can be significant. To assess these difficulties. a detailed investigation of relief-well requirements for such a blowout was conducted.
For this investigation. a worst-case scenario was defined to determine maximum requirements to establish control of the blowout. The prima - assumptions of the scenario are that (1) the well is located in deep water. (2) the reservoir is at a relatively shallow depth, (3) the permeability of the formation is high, (4) 13 3/8/,-in- 134-cmi casing is set near the top of the reservoir, (5) the reservoir contains gas, and (6) the blowout is unrestricted at the seafloor.
(The drilling rig, riser. and blowout preventer (BOP) stack either are not present or are damaged beyond usefulness and offer no resistance to the flow.]
Fig. 1 illustrates a model well for the worst-case scenario. As can be seen, water depth is 1,000 ft [305 m] and the reservoir top is relatively shallow at 4,300 ft [ 1311 m ) 13 3/8-in. [34-cm] casing is set at 4,200 ft [ 1280 m]. The fracture pressure at the casing shoe is, 2,850 psi [ 19 650 kpal and the reservoir pressure is 2,250 psi [15 513 kPa]. Reservoir temperature is 136deg.F [58deg.C].
Flow calculations show that an uncontrolled blowout from such a well could cause a gas flow rate as high as 1,850 MMscf/D 152.98 x 106 std M3/d]. The assumptions for the flow-rate calculations were ( 1) 145 ft [44 ml of reservoir pay, (2) no skin damage, (3) static reservoir pressure of 2,250 psi f 15 5 14 kpal. (4) no water or condensate production, and (5)2.00-darcy 1.97-um2 average permeability.
The gas plume resulting from such a blowout could directly affect an area larger than 425 ft [130 m] in diameter al the ocean surface. The central boil of the plume could be more than 200 ft [61 m] in diameter and as high as 11 ft [3 m] above sea level. Gas concentration at the surface could exceed the lower flammable limit, depending on winds. thus creating hazardous conditions- Such surface conditions eliminate the possibility of positioning a rig over the blowout well and attempting to re-enter or repair the wellhead and BOP'S.
This paper investigates the relief-well requirements and defines the required special procedures and equipment for a direct dynamic kill of such a blowout well,
Kill Method Selection
A subsea blowout can be brought under control by vertical re-entry into the blowout well by a rig positioned over the well, reestablishing pressure integrity of the wellhead/BOP by subsea means, drilling a relief well for a reservoir flood kill, or drilling a relief well for a direct dynamic kill.
Vertical re-entry into the blowout wellbore was not considered because of surface problems associated with the gas plume and flammable gas concentrations. Re-establishment of the wellhead/BOP pressure integrity by subsea means was not considered practical because of water depth and high water currents induced near the wellhead by the gas flow.
The reservoir flood kill method requires drilling a relief well parallel to and near the blowout wellbore. Seawater is injected into the reservoir to reduce formation productivity and gradually kill the damaged wellbore. The method has been used successfully in the past and would be considered in the planning of a relief well. Fig. 2 shows that a flood kill relief well would be an S-shaped directional well to run parallel to the blowout wellbore through the production interval. The relief-well hole angle would be higher than in the direct kill method in the example. Hole stability problems could also be a consideration. Reservoir thickness in the blowout well and variable formation permeabilities are potentially uncertain parameters that could reduce the chances of an effective flood kill.
A significant uncertainty associated with the flood kill method is the possibility that the flood kill operation could inadvertently become a direct kill operation. This could occur either by accidental intersection of the blowout wellbore by the relief well or by frac-turing into the blowout wellbore during flooding operations. The potential for a flood kill becoming a direct kill adds considerable risk to the operation if the relief-well rigs are not equipped with the pumping capability for this contingency.
The direct dynamic kill method, while requiring approximately twice the pumping capability of the flood kill method, represents the safest approach for the blowout case discussed here. The direct kill method avoids the downhole uncertainties of the flood kill method and the added surface equipment requirements are manageable. The relief-well hole angle requirement for the direct kill method is less than that for the flood kill method: this allows greater flexibility in determining surface positions for the relief-well rigs.
The main requirement for the direct kill is to establish direct communication with the blowout well. Direct intersection can bachieved either by drilling directly into the blowout wellbore or by establishing a hydraulic conduit between the blowout well and the relief well (fracture). Direct wellbore intersections can be achieved with existing equipment and procedures. Proper planning of both the potential blowout well and relief wells can improve chances of success should a blowout occur.
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