HPHT Drilling and Completion Design for the Erskine Field

Abstract

This paper summarises the factors influencing the well design for a high pressure high temperature (HPHT) field development using a Not Normally Manned Installation (NNMI) in the UK sector of the Central North Sea (CNS). Introduction The Erskine gas condensate field is a 50% Texaco / 50% BP venture and will be the first HPHT field developed in the North Sea with first gas scheduled for 1997 (Fig. 1). The field development concept is to install a not normally manned installation (NNMI) with multiphase export of produced fluids to the Lomond platform from six platform wells. Drilling and completion operations will be carried out using a harsh environment jack-up rig in cantilever mode. Primary functional requirements for the wells include high reliability, high productivity and the ability to perform through tubing plug-backs. Reserves in the core area are found in three separate but generally overlying Jurassic sandstone producing horizons, the Kimeridge, Erskine, and Pentland sands. A multi-discipline project team consisting of reservoir, production, drilling and facilities engineers was set up to progress the development concept. Specific well design principles were adopted and an iterative approach was used to produce a robust and reliable drilling and completion design that is compatible with the overall development concept and provides reliability on a NNMI in HPHT service conditions. Jackup drilling will commence over the platform jacket which will be installed over an existing sub-sea appraisal well in the spring of 1996 (Fig. 2). Two wells will be predrilled through the jacket structure and suspended prior to the platform topsides deck being lifted into place in 1997. The appraisal well will be tied back and wells will then be completed ready for commercial gas export in late 1997. Further wells will then be drilled and completed as required. Platform Concept Outline By North Sea standards Erskine is a marginal field (335 MMSCF gas, 66.5 MMBBL oil). The resultant development has revolved around this in order to make development economic. The following lists the main features of the development.Simple NNMI 12 slot wellhead platform providing unprocessed multiphase fluids export to host platform with a projected field life of 15–20 years.Platform design and slot layout which enables access to all slots for cantilevered jack-up drilling in the 300 ft water depth. Well Design Considerations Primary considerations for the well design are:Reservoir fluids containing H2S and CO2. Reservoir pressure +/-14,000 psi, temperature 350 F, initial surface shut-in pressure 10,600 psi (Table 1).Design flow rates required from each well will be up to 60 mmscf/day of gas.The wells that are initially completed as Pentland sand producers will water out and require to be plugged back and recompleted as Erskine sand producers. Due to availability and cost of large jack-up rigs, this requires to be a rig-less operation. P. 103

Designer Casing for Deepwater HPHT Wells

“…Sizes, weights, and grades have been developed to address specific well needs, such as the 12-1/8" 90.0 ppf C-110 x 10-3/4" 73.0 ppf C-110 x 10" 72.0 ppf Q-125 intermediate casing used at Erskine, the first HPHT well in the North Sea. 11 There appears to be little news when it comes to custom OCTG.…”

Importance of Completion Design Considerations for Complex, Hostile, and HPHT Wells in Frontier Areas

“…The limits of C110 tubulars are determined by the proprietary specification of each steel manufacturer and are not specifically identified within Corrosion Resistant Alloys (CRA's) can be used for corrosive environments, but the exact metal specification needs to address the effects of Chloride Stress Cracking (CSC), high temperature corrosion, combined SSC and CSC, and potential exposure to acid 5,7,8 . Once a CRA material is considered technically suitable, the predominant challenge is to determine if this is the most cost effective solution for coping with the desired operating parameters.…”

“…High density oil based mud will be heavily ladened with barite and has been known to cause setting and sealing problems. This can result from plugging of communication ports or from residual mud adherence to the walls of the casing at the high bottomhole temperatures 5 . The preferred setting environment of the final packer is a clear brine after the casing wall has been effectively cleaned.…”

“…This can be a limiting factor in "traditional" packer style completions thus several operators have adopted monobore style completions where the tubing has virtually the same inside diameter as the production liner 5 . The annulus between the tubing and production casing is isolated by a tubing seal assembly that is landed or latched into an integral PBR on the liner top packer.…”

“…Over the past several years, more effective inhibitors have been identified and significant improvements in the safe handling procedures of these brines have been enacted. These brines still cannot be used as long term packer fluids (annular fluid above the packer), thus common practice has been to use an inhibited slightly saline water, like potassium chloride or seawater 3,5,12 . In addition to the corrosion concerns, the packer operating envelopes can frequently be exceeded in a tubing leak load case with heavy weight packer fluid.…”