No abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCarbonate and sulphate scales are the most common types of mineral deposit associated with the recovery and processing of hydrocarbon and associated produced water. In three high temperature fields (>140C) within the North Sea more usual scale types have been observed namely zinc and lead sulphide. Conventional inhibitors cannot control these scale types and their removal by chemical means can result in the generation of toxic gas (H 2 S). The conditions for the formation of these unusual scale types is described and well as the economic impact these deposit had on hydrocarbon production of these fields. In this paper the development of a novel scale inhibitor package and its successful application in these fields is described.Field evaluation of the inhibitor types used to control sulphide scale is described in this paper as well as the details on how the field trials were planned, carried out and evaluated.Mechanical and chemical removal are also discussed as an alternative to inhibition.The finding of this paper significantly increase the industries understanding of sulphide scale deposits in terms of mode of formation and mechanism of inhibition. The paper stresses the critical factors to be evaluated within produced water at the early stage of field appraisal/development that can aid in the assessment of the risk of sulphide scale deposition. The development of a novel zinc and lead sulphide inhibitor gives a cost effective, environment friendly alternative to chemical or mechanical removal of such deposits.

This paper presents field results from two scale squeeze treatments carried out on the same sub sea horizontal well from a field in the North Sea, The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulphate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This utilised a thermally degraded pelted wax divertor to temporally impair injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the mid section of the horizontal well. This paper will show the significance of production logging tool data toevaluate the location of deposited scale and water production prior to a squeeze treatment. Such data was 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 pelted thermally degraded wax divertor to prevent further loss of scale inhibitor to the heal region. The action of the divertor allowed a second scale inhibitor to the heel region. The action of the wax divertor allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of divertor 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 (non-radioactive tracers, inhibitor and ion Concentrations) data were recorded. This data will be used to indicate the success of diversion treatment by comparison with the first squeeze applied to the same well ten months previously. This is the first successful application of a thermally degraded wax divertor to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process up set during flowback and no decline in well production whilst allowing the well bore to be protected from continued sulphate scale formation. This paper clearly shows that with the correct selection of both scale inhibitor, divertor agent together with the utilisation of all available information relating to the reservoir. It is possible to squeeze scale inhibitors into sub-sea horizontal wells without the need for expensive coiled tubing intervention from a diving support vessel. This technology is not limited to horizontal wells and could also be applied tovertical wells with significant cross flow problems to aid in selective placement during scale inhibitor squeezing. P. 633

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.

This paper presents field results from five scale squeeze treatments carried out on sub-sea horizontal wells from the Strathspey field in the North Sea. The development of a squeeze policy is outlined with the utilisation of laboratory coreflood data, computer simulation (SQUEEZE V Code) and the application of a novel solid divertor. This paper outlines the practical difficulties in squeezing sub-sea horizontal wells and how some of the problems can be overcome. Some of the solutions that will be discussed include the use of variations in pump rates to encourage propagation of inhibitor along the well-bore, and the utilisation of fluid diversion techniques (both mechanical and chemical).The significance of production logging tool (PLT) data or good reservoir simulation data to evaluate the location of water production and any cross flow prior to a squeeze treatment design will also be stressed. Details of divertor selection, design simulation and the field results from the five squeeze design strategies that have been implemented will be presented. From this series of field treatments it can be concluded that the wells have all been successfully treated with no process upset during flowback. No decline in the wells' productivity was observed as a result of these treatments. This paper shows that by using divertor agents, and by integrating near well-bore calculations (SQUEEZE V) and PLT/reservoir simulation data, it is possible to squeeze scale inhibitors into sub-sea horizontal wells without the need for coiled tubing intervention from a diving support vessel. Introduction The Strathspey field lies approximately 140 km North East of the Shetland Islands in a water depth of 250 ft. The field consists of two reservoirs: the Statfjord, a gas condensate reservoir, and the Brent, a black oil reservoir.