Selection and Deployment of a Scale Inhibitor Squeeze Chemical for the BP Miller Field

Abstract

The BP operated Miller field arguably produces the most severe barium sulphate scaling waters in the world. There is an operational need to carry out scale squeeze operations almost continually in order to maintain the oil and gas production. In this paper, we will present the challenges overcome proposing and in applying a new downhole product in this challenging environment. The paper will describe the selection process and test protocols needed to identify suitable squeeze inhibitor chemistry and review the laboratory data generated for a specific chemistry. A pre-requisite in assuring the performance of a squeeze chemical on the Miller asset is the ability, for the supplier, to guarantee a 24 hour turn around time for residual inhibitor analysis. The conventional detection method for the type of chemistry selected is the hyamine test, which is time consuming and can be inaccurate. This paper will also include results from the Baker Petrolite High Performance Liquid Chromatography (HPLC) method for residual analysis, developed for detection of polymeric scale inhibitors in produced water. This method has the advantage of producing accurate results in a very short time frame. The paper will also review the actual deployment of this chemical in the field, and demonstrate how the implementation of the selected chemistry resulted in immediate annualized operational savings to BP of an estimated $2.9MM on a single well. The results of Squeeze V modeling are also reported, demonstrating how the squeeze applications are being optimized to bring even larger operational savings to BP by improving the squeeze lives on selected wells. Introduction The Miller field was discovered in 1982 in UKCS blocks 16/7b and 16/8b in the South Viking Graben. It is approximately 270 km Northeast of Aberdeen and the oil bearing structure is some 4000 meters beneath the seabed. The Miller reservoir is Upper Jurassic submarine fan sandstone with medium to fine grained quartz sandstones. The field is a low relief structure with the oil water contact at ~ 13418ft. The platform was installed in May 1992 with production commencing in 1992 at initial reservoir pressures of 6500 psia. Seawater injection is utilised on Miller in order to maintain reservoir pressure with 200,000 – 300,000 bpd seawater utilised through a number of injector wells. Oil production peaked at 150,000 barrels/day which was maintained until 1997. Sandstone is the major component of the Miller reservoir, it accounts for > 80% of the reservoir volume. Smaller elements of carbonate cementation and feldspar are also noted. Trace levels of mica and glauconite are also present and no significant levels of swelling clays are observed. In general, porosity's of 14 15% are found and permeability ranges from 200 millidarcy (mD) to > 1000 mD. Challenges Within the Miller field, seawater breakthrough from the injectors varies significantly. Wells with < 30% and > 60% seawater cut are felt to be comfortably under control for scale deposition. Wells that occur in the 30% 60% region (i.e. the worst case scenarios) are frequently treated with scale inhibitor squeeze treatments. A number of these wells are squeezed approximately every 7 days. This high frequency is due toHigh minimum inhibitory concentration (MIC) requirement for worst case seawater formation water ratioRapid release of adsorbed chemical such that return concentration rapidly falls below the MIC.

Comparison of Streamline Reservoir Simulation of Brine Flow, Mixing and Barium Sulphate Induced Formation Damage with Observed Produced Water Chemical Data to Aid Scale Management

“…Based on the information described above and other publications (Bourne et al, 2000;Wylde et al, 2006;Poynton et al, 2004), it is clear that the Miller field has a high potential for very sever barite scale problems and moderate celestite and calcite scaling tendencies, which then necessitates scale inhibitor squeeze treatments to control the scale deposition in the near well bore formation and production tubing.…”

“…Porosity of 14%~18% is exhibited and permeability ranges from 200mD to over 1000mD (Poynton et al, 2004). Reservoir pressure is 45,000 kPa and reservoir temperature is 121°C.…”

“…The Miller reservoir is in the Upper Jurassic Brae Formation turbidite sands, similar to the Brae Formation reservoirs in South and Central Brae. It is sealed by the Upper Jurassic Kimmeridge Clay Formation, which is also the source rock (Poynton et al, 2004). …”

Modeling a Series of Nonaqueous Field-Scale Inhibitor Squeeze Treatments in the Heidrun Field

“…In this study, we followed the same procedure that has been shown by others previously (Lopez et al 2005;Poynton et al 2004). The coreflooding modeling gives a first estimate of a pseudoisotherm that describes the interaction of the SI with the rock formation as a function of the amount of chemical retained vs. the concentration of chemical in solution.…”

Modelling a Series of Non-Aqueous Field Scale Inhibitor Squeeze Treatments in the Heidrun field

“…In this study, we followed the same procedure that has been shown by others previously (Lopez et al, 2005;Poynton et al, 2004); the core flooding modelling gives a first estimate of a pseudo isotherm that describes the interaction of the SI with the rock formation, as a function of the amount of chemical retained versus the concentration of chemical in solution. Generally, field SI return profiles are not matched exactly in the models using the pseudo isotherm derived from a coreflood for a particular SI for a specific formation (Sorbie et al, 1992;Yuan et al, 1994).…”