Dynamic Kill of an Uncontrolled CO2 Well
Authors: Lynch Richard D. , McBride Edward J. , Perkins Thomas K. , Wiley Michael E. 
Published: December 2007

Summary
In March 1982 a CO2 well in the Sheep Mountain Unit, CO2 blew out. This well was brought under control in early April 1982 by the dynamic injection of drag-reduced brine followed by mud. This paper discusses the events and field activities that followed the blowout and led to the successful kill operation. Also included is a discussion of two initial, unsuccessful kill attempts, associated mechanical problems, and the understanding gained therefrom. Analyses of wellbore and reservoir hydraulics led to an understanding of the freely flowing well. Injection of kill fluid down the drillpipe was possible, but the small pipe diameter, particularly that of the heavy wall drillpipe. pipe diameter, particularly that of the heavy wall drillpipe. significantly limited the rate of kill-fluid injection. The kill operation was further complicated by the high flow capacity of CO2 from the reservoir. The high CO2 flow rate efficiently gas-lifted the kill fluid up the annulus and thus tended to maintain a low bottomhole pressure (BHP). Further analysis of the hydraulics of the system suggested two alternatives for dynamically killing the well:use of highly drag-reduced fluids of moderate density such as water or brine, anduse of non-drag-reduced mud with a density greater than about 18 Ibm/gal [2100 kg/m3].
The well was killed successfully with 10.5-lbm/gal [1260-kg/m3] brine, which exhibited 72% drag reduction in surface lines and drillpipe at an injection rate of 60 bbl/min [570 m /h].

Introduction
On March 17, 1982, CO2 Well 4–15-H in the Sheep Mountain Unit, CO2 blew out. Four unsuccessful attempts were made to kill the well with conventional weighted-mud techniques in the period from March 17 to March 23, 1982. By March 24, the well was blowing out of surface fissures on the west slope of Little Sheep Mountain directly above the drillsite. Two factors were the primary causes of the failure of the conventional kill technique. First, while injection of kill fluid down the drillpipe was possible, hydraulic constraints and pressure limitations significantly limited the rate of kill-fluid injection. Second, the kill operation was further complicated by the high flow capacity of CO2 from the reservoir, estimated at that time to be in excess of 90 ⨯ 10 scf/D [2.5 × 10 m/d] (later calculated to be at least 200 × 10 scf/D [5.6 ⨯ 10 m /d]), which efficiently gas-lifted the kill fluid up the annulus. Because no progress had been identified by use of the weighted-mud methods, the dynamic kill technique was used. Basically, this technique uses frictional pressure losses to supplement the hydrostatic pressure of a lightweight kill fluid injected at high rate at or near the bottom of the well. On April 3, 1982, the well was successfully contained by this technique using drag-reduced calcium chloride (CaCl,) brine as the kill fluid followed by weighted mud loaded with lost-circulation material to rebuild the filter cake on the producing zone.

Description of the Sheep Mountain Unit
The Sheep Mountain Unit is located in Huerfano County, in south central Colorado. The unit is topographically dominated by Sheep Mountain (elevation 10.635 ft [3242 m]) and Little Sheep Mountain (elevation 9,616 ft [2931 m]). Slopes vary from nearly level, in bottoms and on terraces, to 40% in the foothills and to 60% on the talus slopes of the two mountains. As a result of this topography, all development wells are directionally drilled from centrally located drillsite pads to develop the underlying Dakota and Entrada CO2 reservoirs properly. The surface spacing of the wells on a given drillsite is 100 ft [30 m] center-to-center. The bottomhole spacing is 1,000 ft [305 m] nominal distance between wells at the target depth, which is the Dakota formation (+/–3,500 ft [ +/–1070 m]).

General Well Design
The general well design called for 10 3/4 -in. [27-cm] surface casing to be preset at 300 ft [91 m] below ground level and cemented to surface by use of a small, highly mobile rotary spud rig. A rotary drilling rig would then be moved over the 10 3/4-in. [27-cm] surface casing, and the well would be directionally drilled to total depth (TD). Oil-based mud was used for the drilling fluid to inhibit the water-sensitive Pierre shale interval (surface to1,500 ft [ +/–457 m]) and to control differential sticking in the Dakota and Entrada sands. A production string consisting of 7 5/8-in. [ 19.4-cm] casing would be run to TD and cemented to surface. The well would then be completed with a workover rig at a later date.

History of Well 4–15-H
Well 4-15-H was the fourth development well to be drilled from Drillsite 2. The well was planned to penetrate the Dakota sand in a highly productive area of the CO2 reservoir.
JPT
P. 1267