Novel Wax-Diverter Technology Allows Successful Scale-Inhibitor Squeeze Treatment in a Subsea Horizontal Well

Jordan, M.M. (Nalco/Exxon Energy Chemicals Ltd.) | Edgerton, M.C. (Texaco North Sea UK Co.) | Cole-Hamilton, J. (BJ Services) | Mackin, K.W. (Nalco/Exxon Energy Chemicals Ltd.)

OnePetro 

Summary

In this article we present field results from two scale squeeze treatments carried out on the same subsea horizontal well from the Strathspey field in the North Sea. The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulfate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This latter utilized a thermally degraded pelleted wax diverter to temporarily impair the injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the midsection of the horizontal well.

In this article we show the significance of production logging tool data to evaluate the location of deposited scale and water production prior to a squeeze treatment. These data were used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelleted thermally degraded wax diverter to prevent further loss of scale inhibitor to the heel region. The action of the wax diverter allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of the diverter selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (nonradioactive tracers, inhibitor and ion concentrations) data were recorded. These data will be used to indicate the success of the diversion treatment by a comparison with the first squeeze applied to the same well 10 months previously.

This is the first successful application of a thermally degraded wax diverter to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process upset during flowback and no decline in well production while allowing the well bore to be protected from continued sulfate scale formation. In this article it is clearly shown that with the correct selection of both the scale inhibitor and diverter agent together with ulitization of all available information relating to the reservoir, it is possible to squeeze scale inhibitors into subsea horizontal wells without the need for intervention by expensive coiled tubing from a diving support vessel.

Introduction

The Strathspey field lies approximately 140 km northeast of the Shetland Islands in water 250 deep. The field consists of two reservoirs, the Statfjord, a gas condensate reservoir, and the Brent, a black oil reservoir.

Production is through a subsea manifold tied back by a network of pipelines to the Ninian Central platform. The manifold is 16 km in distance from the platform.

The Brent reservoir consists of a typical North Sea Brent sandstone sequence with several layered sand units on top of each other, each with a varying degree of vertical communication. The Brent reservoir is produced by seven wells with a further two wells providing water injection support. A map of the reservoir is presented in Fig. 1. The reservoir quality varies dramatically between sand units with permeabilities ranging from 100 to 1,000 md.

The Strathspey field has produced to date 52 MMbbl of oil and 110 Bcf of gas. Strathspey had produced at a plateau for four years and since 1997 the field has entered a production decline phase. The current field water cut is 76% with individual wells ranging from 64% to 90% water.

Four of the fields' seven producing wells are near horizontal producers and produce from several different pressured layers. The horizontal wells are capable of lifting between 10,000 and 35,000 bbl of fluid from the reservoir. This represents a large volume of water produced and often consists of both sea water and formation water produced from different layers within the reservoir.

A capacity for both barium sulfate scale and calcium carbonate scale exists within the fluids produced from the field. The desired method to prevent scale formation in both the near wellbore area and the tubing is squeezing. The squeeze process involves the introduction to the near wellbore area of a scale inhibitor which adsorbs to the formation and then returns slowly, providing protection against scale formation. The scale treatments described in this article are applied by a utilities pipeline 3.15 in. inner diameter (ID) that is bullheaded into the near wellbore formation. Typical injection rates are 4 bbl/min. The fluids are pumped using the resident cement unit on the Central platform.

This method of preventing scale deposition had proved successful in the vertical wells of this and other Texaco UK assets, however this method of application proved to be unsuccessful in horizontal, multilayered wells. Over a 1,000 BOPD was lost from a well as a result of scale buildup. This scale was removed from the tubing using a scale dissolver, however a new method of placing the inhibitor was required if this loss due to scale deposition was to be avoided.19

Formation Water Chemistry.

There are variations in the formation water chemistry in different wells within the field. This variation reflects the slightly different zones in which each well is completed. Typically the salinity of the formation water is 26,340 mg/L total dissolved solids (TDS) which is slightly lower than that of seawater. The barium and strontium levels within the pre-breakthrough seawater are in the range of 25 to 50 ppm barium and 20 to 30 ppm strontium, and 220 to 230 ppm calcium and 750 to 1,500 ppm bicarbonate. The maximum mass of barium sulfate scale is predicted to be deposited at a <5% seawater breakthrough, however the maximum mixed brine supersatuation is predicted to occur at about 50% seawater. A typical formation water analysis is presented in Table 1 . Carbonate scale formation is also expected based on the formation water composition and the operating temperature and pressure of the field and process systems. If uninhibited, production of a mixture of seawater/formation water will result in the deposition of sulfate scale. Carbonate scale is also probable when water is produced. The deposition of scale could occur in perforation tunnels or production tubing. Scale deposition will cause flow restrictions and possibly compromise the effectiveness of subsurface safety valves.