One of the methods to control the formation of hydrates in oil and gas pipelines is the injection of kinetic hydrate inhibitors (KHIs). The accepted understanding is that KHIs slow down or interfere with hydrate nucleation, forcing an extended "induction time" (time to emergence of viable hydrate crystals) at a given subcooling. As a result, KHIs are commonly evaluated by measuring induction times in the laboratory. However, this experimental approach has some limitations, notably in that data can be stochastic due to the nucleation element, raising questions over reliability/transferability, with multiple repeats often required to establish clear trends. As KHIs also exhibit powerful growth inhibition properties, a new crystal growth inhibition (CGI) method for the evaluation of KHIs has been previously developed with the aim of providing a means to more rapidly evaluate KHIs in a robust manner. This method shows that KHIs induce a number of well-defined hydrate CGI regions with different growth rates as a function of subcooling, and these can be used to reliably evaluate inhibition performance on quite short time scales. In this work, we present the results of an experimental program for the qualification of a commercial KHI to be used in a greenfield development using this CGI method. The aim of the laboratory work was to determine required inhibitor dosage, investigate the effects of a corrosion inhibitor (CI) on KHI performance, and evaluate the potential for KHI inhibition during shut-in/restart, in addition to flowing conditions. The program focused on CGI methods for evaluation in addition to standard induction time measurements. A methodology to recreate pipeline flowing, shut-in, and restart conditions was also developed and used. The CGI approach was found to offer advantages in the speed of KHI assessment and provides a useful decision-making tool with respect to KHI field deployment. Data also correlate with and compliment traditional induction time results which still provide valuable information on the degree of "nucleation" inhibition offered on top of crystal growth inhibition. In addition to offering excellent hydrate inhibition under flowing conditions, results suggested the KHI could readily offer good protection for long periods of shut-in (e.g., >168 h at up to 15 °C subcooling) followed by restart, reducing or negating the need for depressurization procedures in the event of shut-in.
While barium stripping is commonly observed in sandstone reservoirs where seawater mixes with formation water that may be rich in calcium, strontium and barium ions, this paper presents evidence for in situ sulphate stripping in a sandstone reservoir. The formation brine composition suggests that a moderate to severe barite scaling tendency will require inhibitor concentrations in the range of 10–50 ppm to control scale, but in practice concentrations < 5 ppm are adequate. Investigation of the produced brine compositions has revealed that this is due to much lower sulphate concentrations in the produced brine mix than would be expected purely from dilution of seawater with the formation brine. The question this paper addresses is what has caused this reduction in sulphate concentration. The formation brine Mg/Ca ratio is < 0.1. Over geological time frames, the reservoir rock and formation brine will come into chemical equilibrium, the Mg/Ca and Na/Ca ratios in the brine being dependent on the respective ratios in the rock matrix. However, when seawater is injected, this equilibrium is disturbed. Since the Mg/Ca ratio for seawater is ∼ 3, to re-equilibrate an ion exchange mechanism causes magnesium to be retained from the brine phase onto the rock, and in return calcium is released from the rock into the brine phase. This is confirmed by lower than expected magnesium concentrations in the produced brine. The impact of the calcium release into seawater as it is displaced through the hot reservoir is to cause precipitation of calcium sulphate, this process resulting in the observed sulphate stripping. This analysis is supported by the field data and by reactive transport calculations. Implications are drawn for scale management in this and similar fields with high formation water calcium concentrations. Introduction The Gyda field lies on the north-eastern margin of the North Sea Central Trough, on the Norwegian Continental Shelf, 270 km (168 miles) southwest of Stavanger and 43 km (27 miles) northeast of Ekofisk Centre. The offshore installation comprises a conventional 6-legged steel jacket which supports integrated production, drilling and living quarters. Peak oil production topped 20,100 m3/day (126,000 stb/day) during 1993. Gyda is currently operated by Talisman-Energy Norge A/S (61 %) on behalf of DONG (34 %) and Norske AEDC A/S (5 %). It was originally operated by BP Norway Ltd., and when it came on stream in July 1990, it was the deepest, hottest and lowest permeability oilfield in the North Sea[1]. Gyda receives limited aquifer support and is developed by waterflood. There are 32 well slots of which currently 15 are for producers with a further 10 wells dedicated to water injection. From the outset it was recognised by BP that the formation water / injection water mix would lead to a severe scaling tendency[1]. The current operator, Talisman, have sought to review the scale management process to ensure that any lessons that can be learned from analysis of the earlier stages of production may be applied to ensuring effective scale control to the end of the field life cycle. It is the results of that review process that are presented in this paper. Reservoir Description and Field Development Gyda hydrocarbon reserves are contained in Upper Jurassic shallow marine sands. Reservoir depth is 3,650 - 4180 m (11,975 - 13,665 ft) subsea, initial temperature was 160 °C at 4,155 m (320 °F at 13,362 ft) and initial pressure was 604.5 bar at 4,155 m (8,768 psia at 13,362 ft). Some areas of the reservoir are heavily faulted, while others are moderately faulted. The sands are bioturbated, and in areas they are interbedded with calcite stringers. The field is divided into three regions, main field, the South-West and Gyda South with different PVT regions. The main field has a dip-closure in the western parts, called the C-sand area. The crest area has closure in the east by the Hidra fault system while it pinches out to the south. The downdip area has closure to the south by a Triassic high, while the southern area (Gyda South) is a tight rollover on the western bounding fault of the horst block. The field is moderately faulted (Fig. 1), and production has demonstrated that communication in some reservoir layers is good. Nevertheless, several distinct field compartments are defined from pressure data, and geochemical data from Gyda South indicate that sealing faults controlled the filling and cementation history[1]
Summary Over the years, environmental legislation has forced changes in the types of scale-inhibitor molecule that can be deployed in certain regions of the world. These regulations have resulted in changes from phosphonate scale inhibitor to polymer-based chemistry, particularly in the Norwegian and UK continental shelf where phosphonates have been either on the substitution list or phased out for many applications. Over the past 10 years, significant improvements in inhibitor properties of the so-called "green" scale inhibitors have been made. However, for one particular operator, the squeeze application of this green scale inhibitor resulted in poorer than expected treatment lifetimes and significant operating cost because of the frequency of retreatment. To overcome the increasing operating cost, an evaluation was made of the current treatment chemicals vs. the older, more-established phosphonate scale inhibitors. The results for the laboratory evaluation suggested that the older chemistry would extend treatment life and reduce operating cost. A case was made to the legislative authority, who approved the use of the phosphonate scale inhibitor, and field applications started. The squeeze lifetimes for the red phosphonate chemistry were shown to be significantly better than the existing yellow/green inhibitors. During the following months, other scale inhibitors with improved environmental characteristics were developed and evaluated. One such molecule was shown to have similar coreflood retention to that of the applied red phosphonate and presented no formation damage. This paper presents the laboratory evaluation of the new scale inhibitor, and illustrates the improvement observed with this new inhibitor through field squeeze-treatment results from a well treated with both the red and new yellow environmental profile inhibitor chemicals. This paper outlines the challenges with environmental legislation and how it has been possible to develop technical solutions (in terms of environmental vs. safety issues and with new inhibitor chemicals) to meet the challenges of offshore scale control.
Over the years environmental legislation has forced changes in the types of scale inhibitor molecule that can be deployed in certain regions of the world. These regulations have resulted in changes from phosphonate scale inhibitor to polymer based chemistry, particularly in the Norwegian and UK continental shelf where phosphonates have either been on the substitution list or phased out for many applications. Over the past 10 years significant improvements in inhibitor properties of the so called "green" scale inhibitors have been made. However for one particular operator the squeeze application of this "green" scale inhibitor resulted in poorer than expected treatment lifetimes and significant operating cost due to the frequency of retreatment. To overcome the increasing operating cost an evaluation was made of the current treatment chemicals vs. the older more established phosphonate scale inhibitors. The results for the laboratory evaluation suggested that the older chemistry would extend treatment life and reduce operating cost. A case was made to the legislative authority who approved the use of the phosphonate scale inhibitor and field applications started. The squeeze lifetimes for the "red" phosphonate chemistry were shown to be significantly better than the existing "yellow/green" inhibitors. During the following months other scale inhibitors with improved environmental characteristics were developed and evaluated. One such molecule was shown to have similar coreflood retention than the applied "red" phosphonate and presented no formation damage. This paper presents the laboratory evaluation of the new scale inhibitor, illustrates the improvement observed with this new inhibitor via field squeeze treatment results from a well treated with both the "red" and new "yellow" environmental profile inhibitor chemicals. This paper outlines the challenges with environmental legislation and how it has been possible to develop technical solutions (both in terms of environmental vs. safety issues and with new inhibitor chemicals) to meet the challenges of offshore scale control.
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