TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSouth-Pars Phases 2&3 development in Iran is a "wet scheme" base design: no process is performed offshore, all the produced fluids (sour gas + condensate + water) are directly sent to shore through two 32" 109 km long sea lines. Corrosion and hydrate protection is based on buffered glycol (MEG+MDEA) which is regenerated onshore and sent back to the platforms through two 4½" piggyback lines.The concomitant injection of a Kinetic Hydrate Inhibitor (KHI) and a Corrosion Inhibitor (CI) was initially considered as a back-up solution. This paper presents the field experience with KHI and CI injection which had to be applied for the field start-up during respectively 125 days and 80 days for each sea line.This case represents the first large field application of KHI in the Middle-East and the potential of such Low Dose Hydrate Inhibitor (LDHI) is underlined.
Low dose kinetic hydrate inhibitors, developed as an alternative to thermodynamic inhibition of gas hydrates, are a branch of specialty treatment chemicals that is still considered "novel". Such inhibitors have only been a commercially viable alternative to hydrate prevention treatment in the last three years. During and subsequent to this kinetic inhibitors have been deployed and developed successfully for both mature assets and new developments in the North Sea. The kinetic inhibitors developed are termed Kinetic Hydrate Inhibitors, or KHI. Currently a KHI is being successfully deployed in the Hyde West Sole system in the Southern North Sea, and in May of 1998 the Eastern Trough Area Project (ETAP) will start up operations and will use KHI from day one of production. Much has been learned from the development and introduction of KHI products with careful consideration being given to any potential effect that will compromise, not only the production operations, but also the efficacy of any additional additives. Experience has shown that each system must be treated as an individual and the inhibitor tailor made to suit. Here water chemistry, gas composition, temperature, and application all play a major role in the decision process. The use and application of this information, enabling the selection of the most appropriate material can be termed as a complete systems approach. This paper highlights the rationale behind this approach and elaborates on the aspects associated with the deployment of KHI, that experience has shown to be major limiting factors. P. 397
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSouth-Pars Phases 2&3 development in Iran is a "wet scheme" base design: no process is performed offshore, all the produced fluids (sour gas + condensate + water) are directly sent to shore through two 32" 109 km long sea lines. Corrosion and hydrate protection is based on buffered glycol (MEG+MDEA) which is regenerated onshore and sent back to the platforms through two 4½" piggyback lines.The concomitant injection of a Kinetic Hydrate Inhibitor (KHI) and a Corrosion Inhibitor (CI) was initially considered as a back-up solution. This paper presents the field experience with KHI and CI injection which had to be applied for the field start-up during respectively 125 days and 80 days for each sea line.This case represents the first large field application of KHI in the Middle-East and the potential of such Low Dose Hydrate Inhibitor (LDHI) is underlined.
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.
Mineral scale deposition is a significant impediment to efficient operation of oil and gas facilities. Deposition control strategies include brine demineralisation, chemical inhibition and mechanical intervention. Mitigation costs are highest at offshore locations requiring well intervention and include significant production deferment. Hydrocarbon production in the Danish sector of the North Sea has a number of specific regional challenges as reservoirs are often carbonate with high produced water calcium concentration resulting in a high potential for carbonate scaling. Secondary production techniques such as water injection flooding to maintain pressure are used and sea water is pumped directly into the reservoir introducing sulphate leading to downhole mineral scale deposition of barium sulphate, strontium sulphate etc. The offshore location of production facilities dictates that interventions are expensive and put pressure on valuable offshore bed spaces. This paper reports results of field application of a recently introduced scale control technology based on high frequency electromagnetic AC signals generated and impressed onto a well head or associated piping conduit. Field trial data is provided from a production well with a history of scaling where production pressure was held back to reduce scaling severity. Field trial data describes the impact of the technology in preventing scale in a high value well. Analysis of the results showed that physical treatment using this alternative approach effectively controlled scale deposition such that the production systems was protected and the production benefits included increased reliability of gas lift valves, cessation of any tubing acid washes and enhancing production. The economic value added and reduction in risk to personnel and emissions are described. An extended (9 month) pilot test has allowed production to be increased and no mineral scaling has been detected. The results achieved are promising. Stable and no lost production added a value to the producing asset and avoided significant revenue loss to the operator.
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