TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents an overview of BP's approach to Hydrate Management on new Gulf of Mexico (GoM) Deepwater Developments and Operations using the first and second generation (low and high water cut) Anti Agglomerate Low Dosage Hydrate Inhibitors (AA LDHIs). It also describes how these AA LDHIs are used in conjunction with more conventional hydrate management approaches to reach an optimal cost effective field hydrate management solution.The paper also outlines how the challenges outlined by BP and other major oil producers to the oilfield chemical suppliers at various subsea conferences were taken seriously, and how suppliers have risen to these challenges both in terms of cost, chemical technology development and product delivery to the field.Logistics, HSE, chemical injection and life of well operating envelope challenges need careful consideration at all stages of hydrate management and the paper outlines an integrated approach to cover these on a life of asset development. The impact of AA LDHIs and methanol on downstream transportation and refining facilities are also described as well as impacts on crude marketability and crude quality banks.The paper will touch on all these aspects and outline new challenges that are being faced as we move towards High Pressure High Temperature (HPHT) Developments with record water depths and drilling depth challenges.

In recent years, BP has moved into reservoirs in deep water subsea projects where sea water flooding is required for reserves recovery. The introduction of sulfate rich seawater into a reservoir producing a formation brine rich in barium ions significantly increases the potential for barium sulfate scale deposition. This type of scale is not acid soluble, unlike the carbonate based scales traditionally encountered in many regions. Alkaline based chelants, such as EDTA and DTPA, are only effective at removing small accumulations. Mechanical removal is generally considered to be the only effective removal option for significant sulfate scale deposits in the tubing but is not appropriate for removing scale from within the near well bore area or within a frac-pack or screen. Thus the recommended management strategy is one of prevention rather than remediation.

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Summary Barium sulfate scale deposition in the near wellbore, perforations, or production tubing has severely affected well productivity in many North Sea Fields. This is due to the co-mingling of the sulfate-rich seawater used for reservoir sweep with formation water containing high concentrations of barium ions. Mitigation of this problem is generally achieved by regular "squeeze" deployment of scale inhibitor chemicals which retard scale precipitate formation and deposition. However, in some instances, the scale inhibitor is poorly retained within the reservoir rock matrix and short squeeze lifetimes are experienced. The net result in these cases is frequent well interventions which impact on both well productivity and field profitability. To solve this problem, a scale squeeze enhancer has been developed which acts to enhance retention and subsequent release of scale inhibitor in the reservoir. The first field deployment of this technology was in BP's Magnus asset. The trial demonstrated a more than doubling of the squeeze lifetime of an adsorption chemical. Introduction Magnus Field History. The Magnus oil field lies approximately 160 km north east of the Shetland Islands in the U.K. Sector of the North Sea. The field is located in blocks 211/7a and 211/12a, and is producing through the most northerly platform on the UKCS. The Magnus oil field was discovered by BP in 1974 and first production commenced in August 1983, reaching a peak annual average production rate of 144,301 stb/day in 1994. Reservoir Description. The Magnus field is divided into three producing intervals, the Turonian Reworked Sandstone, which overlays the Magnus Sandstone Member (MSM), which overlays the Lower Kimmeridge Clay Formation. The producing interval initially contained an estimated volume of 1650 mm/stb of oil in place. The MSM lies at a subsea depth of approximately 3000 m and is currently the main producing formation, having originally held 77% of the initial oil in place. The MSM is the most well defined of the Magnus formations, and can be broken down into several discrete sandstone zones or lobes, separated by shale mudstone units, which act as vertical permeability barriers. The typical MSM permeability is in the range 200 to 500 mD, with an average porosity of 21% and a maximum net pay of 108 m. Reservoir Management. The Magnus reservoir is currently being drained by 15 producing wells, while nine further wells, including three subsea tie-ins, are injecting seawater to support the reservoir pressure. However, off-take from the field to date has exceeded the volume injected, resulting in a significant drop in reservoir pressure from an original value of 6,650 psi to a current average of approximately 3,000 psi. In addition, a significant pressure gradient exists across the field, with a maximum of 7,500 psi observed in certain injectors, compared with 2,750 psi measured in several crestal producers. The field is now produced on a voidage replacement basis, however, significant differential pressure exists between lobes as a result of divergent pressure depletion through the MSM. Nature of Scale Problem. An analysis of the ionic composition of the formation waters produced from the various lobes or zones reveals subtle differences in their chemistry; however, in each case the produced water has a salinity almost identical to sea water. In addition, the barium concentration in Magnus formation water is in the range 160 to 220 mg/l. This combination of relatively low salinity and moderate barium loading creates a particularly harsh scaling problem.1 The scale problem is further complicated by the high production rates and relatively low well inventory available from the platform.1 In order to provide high oil rates, several of the Magnus production wells were perforated in multiple lobes to access the oil zones more efficiently. This results in the coproduction of waters with differing chemistry which, if left uninhibited, may lead to a rapid buildup of scale. The deposition of scale within the wellbore can lead to loss in productivity and interfere with the correct operation of subsea safety valves. Inhibition of the scale is, therefore, essential. The average scale inhibition treatment on Magnus, until 1997, protected approximately 300,000 to 800,000 barrels of produced water. However, as many Magnus wells now have high water cuts and, hence, high produced water rates, these treatments have often only lasted between 50 and 60 days. This is clearly unacceptable. In an attempt to improve squeeze life, a wide range of inhibitor chemistries have been evaluated and subsequently deployed on Magnus, including polyacrylates, sulfonated polymers, and a modified polyacrylate-based ter-polymer. These chemicals have been deployed mainly in adsorption-type treatments, although conventional precipitation squeezes have also been formulated and applied in the field. The most effective chemistry evaluated to date has been a modified acrylic acid/maleic acid copolymer. However, short squeeze lifetimes have still been experienced using this chemical. Enhancing Scale Inhibitor Retention. Scale inhibitors injected into the near-well bore region of an oil reservoir can be retained via an adsorption-only process, termed an adsorption squeeze, or a combination of adsorption and precipitation, termed a precipitation or phase separation squeeze.2–5 The selection of the type of squeeze treatment (adsorption or precipitation) is dependent on the physical characteristics of the target well (porosity, temperature, lithology, water production rates, etc.) and the water chemistry.6–8

Calcium carbonate scale impacts oil production in a large number of fields worldwide. This scale is generally managed by acid washing to remove the scale and/or by performing scale inhibition treatments. The methodology adopted is usually cost driven with high cost operations generally selecting scale prevention rather than removal. Recently reported work1 showed the potential to integrate scale removal and scale inhibition treatments into a single package, offering clear economic and technical advantages. The combined treatment inherently reduces well intervention costs and well downtime, and protects the value added by the scale removal treatment - by assuring that all of the zones that are stimulated are also inhibited. Combining acid stimulation chemicals and scale inhibitors is by no means a simple process. Compatibility between the acid, the acid additives and the scale inhibitor presents a significant issue in both live and spent acids. This paper will examine these technical challenges and describes the desired properties of such combined systems. Case histories of recent field trials of combined scale removal and inhibition treatments will be presented, including details of job design, job execution and post-job evaluation. Data demonstrating the scale inhibitor return profile in these treatments will be shown, and lessons learnt from the initial trials will be discussed. Comparative performance data for previous acid treatments will also be presented. Introduction Acid stimulation treatments are often used to improve well performance. Hydrochloric acid (HCl) is generally the acid of choice when calcium carbonate is the suspected damage mechanism, unless corrosion cannot be adequately controlled. For high temperature applications, organic acids have been used in preference to HCl, due to such corrosion concerns.2–3 The stimulation benefit of such an acid treatment is often only maintained if a scale inhibitor is subsequently deployed. Recently reported work1 demonstrated that certain scale inhibitors are not only compatible with HCl but also that they retain their ability to adsorb onto reservoir rock under highly acidic conditions. Hence a scale inhibitor could be deployed directly in the acid system, negating the need for a separate scale inhibition treatment. Previously, it had been thought that scale inhibitors could not perform effectively in the post-acid treatment environment.4 Background Two field trial candidate wells were identified, both of which had sand control completions installed. The wells were in different fields and one of the wells had been matrix acidised approximately one year earlier. The cause of decline in each candidate was inconclusive with both calcium carbonate scale deposition and/or fines migration being plausible options. Both of the wells had already been selected as acid stimulation candidates. Combining scale inhibition with the acid treatment offered the advantage that the treatment could be used not only as a stimulation treatment but also as a diagnostic treatment to assess the dominant damage mechanism.