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This paper was prepared for presentation at the 1998 SPE International Conference on Horizontal Well Technology held in Calgary, Alberta, Canada, 1-4 November 1998.
Abstract 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. 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 document is an expanded abstract.
The practice of scale squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. Many of these studies have focused on sandstone reservoir with less extensive studies carried out on carbonate substrates.
This paper details work carried out using ‘squeeze life enhancer’ (SLE) chemicals within the Preflush and Overflush stages utilising a co-polymer to evaluate this chemicals effect on phosphonate containing scale inhibitor retention process. Phosphonate scale inhibitors are known to provide excellent squeeze lifetimes in carbonate reservoirs due to their strong interaction with the negatively charged formation using hydrogen ion bonding at low pH or calcium ion bridging at higher pH however with the aid of an enhancer chemical it was hoped to help the retention/release process and so provide further improved squeeze lifetimes. The location of the enhancer chemical within the squeeze process was the focus of the study. Enhancing adsorption of the scale inhibitor is not objective of this application study rather ensuring that the retained chemical is released into the flowing brine during production which is a challenge in carbonate reservoirs.
The following figures show the potential mechanism of interaction between the squeeze life enhancer polymer (SLE), scale inhibitor (SI) and the calcium (Ca2+) on the surface of the carbonate rock matrix.
Laboratory work will be presented which evaluates the effect of using a polyaspartate enhancer within either the preflush or overflush stages to extend the lifetime of a commonly applied phosphonate scale inhibitor. These tests have been carried out using pack floods at 85°C with synthetic Middle East produced water and the details of the extension in treatment life observed are correlated to the inhibitor type tested and the sequence of application of the polymer enhancer utilised.
Abstract Calcium carbonate scale was detected in the majority of wet producers in a tight carbonate reservoir in the northern part of Saudi Arabia. Extensive lab work indicated that a phosphonate-type scale inhibitor was effective in mitigating carbonate scale, as well as sulfate scale that were found in a few wells. Field application of conventional scale squeeze treatment in this field is not an easy task for the following reasons:The formation is tight and water blockage is a serious concern. Formation brine contains high Ca concentrations (up to 19,930 mg/L). The formation contains high TDS (up to 231,262 mg/L); therefore measuring low concentrations of the phosphonate inhibitor is a real problem. Nearly 70% of the field is offshore, which imposes limitation on the volume of fluids that can be used. As a result of these challenges, several modifications were introduced to conventional scale squeeze treatments, where a large amount of aqueous phase is typically introduced into the formation. Coreflood experiments were used to evaluate various available options to reduce the amount of aqueous phase introduced into the formation and associated problems. Based on the results obtained from these tests, significant changes were introduced to the preflush, main treatment, postflush, and soaking time. The new modifications were applied at two wet producers in this field. Well Z-C is a vertical well with 70 vol% water cut, 218°F bottom hole temperature, and 78,540 mg/L TDS. Well B is a horizontal well with 5 vol% water cut, 235°F bottom hole temperature and 209,828 mg/L TDS. An extensive wellhead-sampling program was conducted to measure residual scale inhibitor in the produced brines. Both wells responded positively to the treatment. The new modifications have resulted in better well response. Analysis of phosphonate in the wellhead samples was used to determine the MIC for this field. Introduction and Background Field "Z" was discovered in 1964. Oil production from this field is mainly from two carbonate reservoirs: HN and HD. The average thickness of HN and HD reservoirs is approximately 97 and 166 ft, respectively. The average porosity for of the two reservoirs ranges from 16 to 20 vol%, whereas the permeability ranges from 6 to 50 mD for HN reservoir and from 9 to 60 md for the HD reservoir. Bulk XRD analysis of the HN reservoir cores indicates that the zone of interest contains 97–100 wt% calcite and 0–3 wt% ankerite. On the other hand, HD reservoir cores contain 70–92 wt% calcite, 0–30 wt% dolomite and 0–5 wt% ankerite. Production from the two reservoirs started in 1970. The field produces Arabian extra light oil (°API ~ 38). The crude oil has significant contents of CO2 (5 mol%) and H2S (3–5 mol%). The reservoir pressures and temperatures are in the range of 3,900–4,200 psig and 210–235°F. More than 70% of the oil producers are off-shore. Peripheral water injection started on 1974 to maintain reservoir pressure. The injection water (IW) is obtained from 21 water supply wells drilled in a shallow aquifer. The injection water is treated at the injection plant with an oxygen scavenger and a biocide. The water injection plant has high pressure pumps which were designed to provide 1,400 psig pressure. Produced water from this field compliments the waterflood operation using separate disposal wells. Table 1 gives the chemical analysis of three producers from HN reservoir, three producers from HD reservoir and two water supply wells from HW reservoir. The TDS of the HD reservoir brine varies from 33,400 to 292,000 mg/L. Calcium and sulfate ions are in the range of 2,392 - 39,280 mg/L and 150 to 813 mg/L, respectively. The TDS of the HN reservoir brine varies from 27,000 to 230,000 mg/L. Calcium and sulfate ions were in the range of 1,904 - 18,876 mg/L and 263 - 965 mg/L, respectively.