A Remotely Controlled Downhole Valve Used for Completion Installation
- Chris Carpenter (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 2014
- Document Type
- Journal Paper
- 118 - 129
- 2014. Society of Petroleum Engineers
- 2 in the last 30 days
- 121 since 2007
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166271, "A Case Study of Using a Remotely Controlled Downhole Valve for Completion Installation," by Keith Oddie, SPE, and John O'Hara, SPE, Halliburton, and Luis Paz, SPE, Hess Corporation, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
On the basis of a case study in Equatorial Guinea, this paper demonstrates how barrier provisions with remotely controlled open/close technology capabilities enable interventions to be removed from a completion design. The technology described was used in a horizontal subsea producer well drilled to 3460 m. The paper will illustrate how combining downhole electronic control with a full-bore hydraulically operated barrier valve removes any need for running control lines to the surface. Surface-applied pressure and time combinations were used to command remote actuation of the valve.
The Ceiba field is located 35 km offshore Equatorial Guinea, west Africa, and is 241 km south of the capital, Malabo. Located in approximately 700 m of water and in one of six subsea clusters in the development, this well was identified as a suitable candidate for inclusion of the technology outlined in this paper.
To maximize reservoir recovery in this field, the completion strategy included a horizontal openhole gravel pack to provide downhole sand control. The completion engineers felt that this strategy would help meet production objectives such as inflow performance. However, it would also require the well to be drilled at a highly deviated trajectory, which would increase the likelihood of the production packer being set at a deviation beyond conventional slickline capability. The remotely controlled downhole valve offered an alternative plugging method to set the packer, test production tubing, and commission subsurface well-control equipment requiring well interventions, and therefore was included for consideration in the well design. The well design would later confirm that the valve would be installed at a deviation greater than 70°.
Plug deployment with wireline and tractor was evaluated in terms of risk and exposure to cost, and from the results of the evaluation, it was concluded that remote technology should be included in the basis of design. A landing-nipple profile located below the packer provided contingency in the event that the remotely controlled valve failed to close.
The final subsea completion design required that the 547-m reservoir section be drilled along a horizontal trajectory, the openhole horizontal gravel-pack system be installed, and the gravel pack be performed. Retrieval of the gravel- pack service tool and wash pipe would mechanically close the fluid-loss control valve to provide isolation from the reservoir during deployment of the upper completion. It would also provide a means of applying the pressure and time signature required to close the barrier valve.
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