Abstract

As regulatory limits for oil discharge become more stringent and environmental awareness increases, produced water re-injection has become increasingly attractive for operators. However, as offshore developments become more complex, with new fields producing through existing facilities, the PWRI design team must face the problems involved in combining and re-injecting potentially incompatible fluids and/or production chemicals.

The Cleeton facilities in the North Sea provide an example of such a PWRI system. These facilities are the hub for the Easington Catchment Area (ECA) and are due to process fluids from an increasing number of new developments in coming years. This paper describes how the results of an extensive laboratory-based formation damage test program (SPE 80257) were combined with near-wellbore injection simulations and economic modelling studies to enable the economics of the treatment program to be defined. This laboratory study demonstrated that one of the production chemicals present in the expected co-mingled fluids exhibited a significant incompatibility with the formation rock, leading to in situ precipitation near the injection face. This resulted in significant reductions in injectivity. Additional work demonstrated that a number of remedial treatments were available to restore injectivity. Near well-bore injection simulation studies were used to predict the rate of reduction of well injectivity and therefore the timing of requirements for remedial treatments at the injection well. This enabled the economics of the treatment programme to be defined. This in turn allowed the cost benefit of the "PWRI incompatible chemicals" during the production stage to be weighed against the cost of remediation treatments during the re-injection stage. The outcome of this work was to recommend that an alternative chemical strategy was adopted in order to reduce the total costs associated with the proposed PWRI system. Preliminary data from the field implementation of the PWRI scheme is also discussed.

Introduction

The Cleeton field forms part of the BP ‘Villages’ complex in the Southern North Sea. Though production from the Cleeton reservoir ceased in early 1999, the Cleeton facilities continue to be used to handle produced fluids from adjacent fields. Currently, all produced waters on Cleeton are processed prior to overboard discharge.

As part of the development of the Easington Catchment Area (ECA) fields, the Cleeton facilities are being converted into a transportation hub. Phase 1 of ECA involves production from the Neptune and Mercury fields. The hub requirements will then be expanded by the JUNO project, which will require services for a further five ECA Phase 2 fields. Figure 1 shows a schematic of the proposed ECA development. To comply with UK regulatory limits for oil discharge and with BP Federal Goals of eliminating produced water discharge, and to design the facilities for limited access (simple process facilities), it was proposed that the produced waters from the new fields would be processed on the Cleeton platform and then re-injected into a depleted Cleeton production zone, along with produced waters from Phase I fields. The optimal injection well was identified by the project design team as production well C4 (Slot CW01) in the north of the field. This well has excellent reservoir quality, is down dip and remote from potential attic gas in the South around the C1 well (Figures 2 and 3). The characteristics of the selected well are as follows:

  • The reservoir porosity in the C4 well is 15% to 23% (average 17.5%).

  • Average Permeability is estimated at 42md. (From well test).

  • Sand thickness is over 100m, and a mixture of inter-bedded Aeolian, Fluvian and Sabkha units.

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