The Use of Silicate-WBM Facilitates Successful Primary Cementation Operations on the BHP Petroleum Liverpool Bay Development
Authors: Cardno D.G. , Ripley D. , Crawford J.W. 
Published: December 2007

Improved water based drilling fluids incorporating soluble silicates have recently been introduced into the UKCS and Holland, primarily, to drill water sensitive shales. In a departure from this purely inhibitive application, and based upon their field observed ability to consolidate drilled formations through physiochemical interaction, a silicate-WBM was used to avoid overgauge hole while drilling easily enlarged Triassic mudstone sequences in Liverpool Bay. Previous wells drilled at high angle using conventional salt saturated polymer fluids, within realistic hydraulic parameters, produced an overgauge hole. This resulted in poor primary cementation leading to gas migration and annular pressure entrapment which required remedial work. Details are presented of the systematic approach to problem solving and the mechanistic reason for proposing a silicate-WBM. In addition, the paper describes achievement of objective (successful primary cementation) from a pragmatic (ease of logistics) solution and presents comparative field data on operational and drilling fluid performance.

Introduction

BHP Petroleum are carrying out a multi-well drilling programme on their Liverpool Bay Development. The integrated development consists of four fields: Douglas (Oil), Lennox (Oil and Gas), Hamilton (Gas) and Hamilton North (Gas). The fields are located within sight of land, adjacent to areas of scenic beauty and areas of dense population (Fig. 1). Approximately 37 wells will be required to fully develop these fields. The target reservoir is the Triassic Ormskirk Sandstone, encountered at relatively shallow vertical depths (ie. 2200 ft to 2600 ft TVDSS). The reservoir in all cases is slightly overpressured, ranging from 10.1 ppg to 10.4 ppg EMW. Well profiles vary across the fields but typically require MD:TVD ratios of 3:1 and tangent angles of 80 to reach the reservoir objectives.

Discounting recent deposition the youngest formations present are the Triassic Mercia Mudstone Group (Cleveleys, Blackpool, Ansdell) which are interrupted by minor halites (Fig. 2). With few exceptions, all wells drilled in this area have used conventional salt saturated polymer fluids. Salt saturation being necessary to prevent hole washout by dissolution through the halite beds. For these reasons, and also appreciation of environmental sensitivity, a salt saturated polymer fluid was the initial choice for this project. In terms of drilling mechanics this fluid, which incorporates a lubricant to reduce rotary torque and to aid sliding, had provided few problems.

Difficulties have arisen on the gas fields due to gas migration behind both the 13 3/8 in. and 9 5/8 in. casing. This had not been a problem on the 11 Douglas wells, (which were drilled first) due to the very low gas: oil ratio. The first two Hamilton North wells had gas migration and pressure entrapment in the 13 3/8 in. and 9 5/8 in. annuli. This prompted an in-house review, prior to moving to Lennox, which added two and four-arm caliper logs to logging programmes and resulted in modification of cementing techniques with regard to: mud conditioning, slurry design, placement procedures, pipe reciprocation and centraliser design. CBLs were also run to verify cement bond quality.

These measures alleviated the problem in the 13 3/8 in. annuli, but not in the 9 5/8 in. where live annuli were still evident. Caliper log data showed the 16 in. hole sections to be in good gauge but the 12 1/4 in. hole sections were severely enlarged through the mudstone sequences above the reservoir. Hole gauge through the 12 1/4 in. intervals (for L2, L3 and L4) varied between 15 in. to 20 in. Similarly, CBLs revealed that the 13 3/8 in. casing was well bonded but for the 9 5/8 in. casing the cement bond was nonexistent or very poor across the mudstones.

It was concluded that poor primary cementation of the 9 5/8 in. casing, leading to gas migration and entrapment, was due to greatly enlarged hole size exacerbated by hole angle. Effort was then focussed on achieving a better gauge 12 1/4 in. hole.

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