Downhole scale inhibitor (SI) squeeze treatments are a common feature of the scale control plans of many oil operators. However, reservoir formations are large, heterogeneous rock bodies in which fluid flow is strongly determined by the permeability structure.Thus, when a slug of scale inhibitor is injected into the formation, fluid placement is an important issue.To design successful squeeze treatments, it is necessary to know where the injected fluid goes or, even better, we would like to control where the fluid package is placed in the near-well reservoir formation.
In this paper, we go "back to basics", in that we re-derive the analytical expression that describe placement in linear and radial layered systems for unit mobility and viscous fluids.In itself, this is not new since these equations are well known.However, we apply them in a novel manner to describe scale inhibitor placement.We also demonstrate the implications of these equations on how we should analyse placement both in the laboratory and by numerical modelling before we apply a scale inhibitor squeeze.We present an analysis of viscosified SI applications for linear and radial systems both with and without crossflow between the reservoir layers.
Visualisation experimental results are also presented of simple and viscosified slug placement in layered bead packs with crossflow between layers.It is shown that these agree very well with the numerical predictions. Additional calculations on near well placement in radial systems are also presented showing how the theory carries over into real field near-well, heterogeneous systems.Some novel ideas are presented on the application of viscosified scale inhibitor treatments.
Background and Introduction
Chemical scale inhibitors have been applied for many years in downhole "squeeze" treatments.The objective is to have an aqueous phase scale inhibitor (SI) return concentration, [SI], above some minimum inhibitor concentration (MIC) for as long as possible [1-8]. The squeeze lifetime is a strong function of the SI/rock interaction e.g. by adsorption.In a homogeneous reservoir layer, adsorption may be the only retention mechanism governing the SI return from the well.However, reservoir formations are rarely homogeneous but are made up of highly heterogeneous rocks which may have a layered or more complex structure as determined by various sedimentological, structural and diagenetic factors . Here we will consider only layered systems where the various layers have different permeabilities, k (and porosities, f) in the near-well formation.In such systems, SI placement within the formation is an additional aspect of a squeeze treatment that must be considered since this may affect the SI returns.
In most cases, scale inhibitors are applied as aqueous solutions at concentration, typically in the range 10,000 - 150,000 ppm.These solutions usually have a viscosity (m) close to that of a normal injection brine; i.e. ~1 cP at 20oC and 0.3 cP at 100oC.Therefore, apart from a slight temperature effect, the injected brine displaces formation water (FW) at unit mobility.Also, for lighter oils, a unit mobility displacement is often involved although viscosity and relative permeability effects may be more important in heavier oils.In unit mobility injection into a heterogeneous layered linear or radial system, as shown schematically in Fig. 1, the fluid placement into layer i is governed solely by the (kh)i product.That is, injecting fluid at a total volumetric flow rate of QT into an N-layer system of the type shown in Fig. 1, then flow into layer i, Q i , is given by:
It can easily be shown that this is true for unit mobility displacement in a linear or a radial system with or without crossflow.However, this well established result might foster the belief that linear and radial systems are also very similar under viscous slug injection with and without crossflow and this is not the case.
This paper was prepared for presentation at the SPE International Symposium on Oilfield Scale held in Aberdeen, United Kingdom, 11-12 May 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers.
Williams, Helen (Scaled Solutions Limited) | Wat, Rex Man Shing (Statoil ASA) | Chen, Ping (Champion Technologies Ltd.) | Hagen, Thomas (Champion Technologies Ltd.) | Wennberg, Kjell Erik (Statoil) | Vikin, Vigdis (Statoil) | Graham, Gordon M. (Scaled Solutions Limited)
In several high temperature and high pressure (HT/HP) production environments severe downhole carbonate scale formation is often anticipated and effective carbonate scale dissolvers are required. However for most cases the selection of scale dissolvers is conducted under much less severe conditions, involving simple bottle tests conducted at temperatures up to 95ºC and ambient pressure. These tests although generally accepted for screening purposes suffer a number of significant limitations. In addition to the moderate test conditions the low pressure means that carbon dioxide is readily released following the dissolution and results in changes in the test pH which may mean the efficiency of the dissolvers could be overstated.
This paper describes the use of a novel a novel HP/HT "stirred reactor" test rig to more closely examine the relative performance of selected scale dissolvers including organic acids (formic and acetic acids), inorganic acids (16% HCl) and other more conventional scale dissolvers under typical field application conditions. The equipment is specially designed for the extraction and stabilisation of samples at or ‘near' tested conditions and therefore allows the equilibrium dissolution level to be determined under more representative HP/HT conditions. In this work preliminary tests were conducted using 16% HCl under progressively more severe test conditions (RT & 1,500 psi; 150ºC & 1,500 psi and then 150ºC & 4,500 psi. Further tests were then conducted to compare the performance of organic acid based scale dissolvers (formic acid and acetic acid based products) together with other selected scale dissolvers at 150ºC and 4,500 psi and compared with the results obtained for 16% HCl. For these HP/HT tests, samples were collected and analysed after 2 and 20 hours equilibration time and results were compared with those obtained in more conventional "bottle tests conducted at less severe environmental conditions (90ºC and ambient pressure).
In summary the results demonstrate the importance of conducting scale dissolver tests for field applications under more representative (HP/HT) conditions.Of particular significance was the impact of the cooling and pressure reductions.For one of the products tested, although very good dissolution was recorded under the HP/HT conditions, re-precipitation of a different polymorph of calcium carbonate occurred very rapidly resulting in a significant increase in the volume of carbonate precipitation within the reaction vessel and various sample lines. The paper will describe the details of the test equipment used in this work and present a mechanistic interpretation of the various results obtained.
James, J. Stewart (Shell U.K. Limited) | Frigo, Dario Marcello (Shell E&P UK) | Heath, Stephen Mark (Clariant Oil Services) | Graham, Gordon M. (Scaled Solutions Limited) | Townsend, Maria M. (Shell U.K. Limited)
Nelson is a platform development in the Central North Sea approximately 180km east of Aberdeen, producing 38° API oil from a Forties type reservoir with seawater injection pressure support. The high-salinity formation water contains up to 370 mgl-1 of barium, creating a significant scaling risk to the wells upon sea-water breakthrough. The majority of current wells are highly deviated but several horizontal wells with variable permeability exist, which pose a considerable challenge in terms of scale-squeeze placement. N19z is a horizontal well in the North Central region of the reservoir with a 500m cased/perforated producing interval in which breakthrough of sea-water has been confirmed. The well has previously been squeezed, both non-diverted and diverted with wax beads, each with varying success. Earlier reports have examined the effect of applying lightly viscosified fluids on placement of treatment fluids across long intervals to overcome friction and crossflow effects with the potential to assist in treating zones with permeability contrasts1. This approach was pursued to improve the effectiveness of squeeze treatments in long-reach horizontal wells in Nelson, culminating in the successful squeeze of well N19z with a precipitating inhibitor in which all squeeze stages were viscosified. The paper reviews the advantages of the viscosified approach, reports laboratory testing, compares the performance of the squeeze relative with non-diverted and wax-bead-diverted treatments, and highlights some of the pitfalls in applying fully viscosified treatments in both Nelson and other field horizontal or high permeability contrast wells.
Scale control in horizontal wells is recognised as a particular technical and economic challenge, especially if effective chemical placement cannot be guaranteed through conventional bullhead squeeze treatments. With longproducing intervals wellbore friction can make uniform treatment difficult even where no significant contrasts in permeability exist; permeability contrasts can exacerbate this still further, in particular, where highest permeability is found near the "heel" of a horizontal well. Moreover, production from zones of different pressures, can generate wellbore crossflow, which can seriously compromise effective adsorption/precipitation of inhibitor during shut-in. Under some of the aforementioned circumstances even placement using coiled-tubing operations cannot guarantee effective chemical placement. The cost associated with use of coiled tubing is very much greater than that associated with conventional bullhead operations, as have been discussed in a number of recent publications.[1-8]
This paper examines the impact on scale squeeze life of water/scale inhibitor re-distribution during extended shut in periods for bullhead scale treatment in a high permeability reservoir. The Eclipse 100 reservoir simulator was used to examine water re-distribution (gravity slumping) during extended shut in periods for horizontal wells in the Draugen reservoir. The work shows that in certain cases involving long horizontal wells (>1000 ft) in high permeability sands (3-5D) with low vertical/horizontal permeability contrasts, extensive water re-distribution can occur during extended shut-in periods owing to density differences between the injected (aqueous) fluids and the formation fluids. Full field reservoir modelling was then carried out to identify candidate wells within the Draugen field which offered greatest potential for improved chemical placement based on these findings. Near wellbore placement modelling was then conducted to optimize squeeze return lifetimes using gravity re-distribution to improve placement deeper (lower) in the reservoir vs. convention scale squeeze design methods such as larger overflush.
The work demonstrates that for selected cases, gravity re-distribution can be used to improve placement deeper (lower) in the near wellbore area. The modeling work also identifies limitations with the simple "radial" near wellbore models for such cases and identifies those wells in the Draugen field which would benefit from such treatments. An added benefit for low water cut wells was the potential to minimise post treatment lift issues associated with the injection of high volumes of water into the near wellbore for aqueous squeeze treatments, by allowing the injected aqueous treatment to sink away from the near wellbore area. New field treatments have therefore been designed based on the work described. The economic impact of the extended shut in times vs. improved squeeze treatments and deferred oil costs for this field case are also discussed following the field applications.
The scaling potential of Miller wells is widely accepted as being perhaps the severest in the North Sea, if not the world. This creates a unique chemical challenge, the aim of which has always been to extend the lifetimes of scale squeezes across all the wells. A new scale inhibitor has been deployed which has achieved this goal. The chemistry in question is a novel polymeric chemistry which contains multiple functional groups, including phosphorus tagging.
Two years were spent developing and extensively testing the chemical in the laboratory, and the resulting product was assessed against those submitted as part of an industry wide search. The new chemical is now deployed on all Miller wells and performance has been beyond all expectations. Two wells have already seen a doubling in the treatment lifetimes resulting in thousands of barrels of incremental oil production. This is particularly important for Miller, where total operational efficiency is paramount as the cessation of production date approaches.
This paper documents some of the initial laboratory work involved with the development of the new chemical but mainly dwells upon the field treatments on Miller wells A14(19), A17(04), A18(32), A21(02), A25(29) and A26(08), covering almost 50 squeeze treatments. The paper goes on to describe the management strategy as well as the approach adopted to determine the limit of the squeeze life. In every case the chemical has outperformed the incumbent in terms of barrels of water protected and total scale inhibitor efficiency. This outcome is unprecedented on Miller: No other new chemical has delivered such a dramatic and significant improvement in scale control economics.
MILLER FIELD BACKGROUND
The BP operated Miller field straddles Blocks 16/7b and 16/8b in the UK Sector of the North Sea, approximately 145 miles NNE of Aberdeen. The field produces gas (exported down the Miller Gas Pipeline to Peterhead) and oil (exported via the Forties Pipeline System to Grangemouth). Ten producer wells were drilled with first oil in 1992. Production plateau'd in 1993 at 140 MBOD and remained for approximately three years. Water injection was initially through six injector wells and began one year after first oil, peaking at 300 MBWD.
Steady decline in oil production has been apparent since 1997 being paralleled with high and sudden formation and seawater breakthrough. The Miller field has achieved beyond the expected recoverable reserves having produced a little over 340 million barrels of oil. Currently the field oil potential is 16 MBD and water production a potential 80 MBD. Cessation of production (COP) has been proposed as December 2006 and is based upon low flow trials.
The most noticeable aspect of Miller formation water is the barium concentration. At 650 ppm this presents a very harsh scaling regime in the presence of even minor seawater breakthrough. A complete water chemistry analysis has been summarised in Table 1 for the wells currently squeezed with the new polymer. During the production history however a wide range of barium concentrations have been detected at surface, a maximum being a little over 3,500 ppm. The water is otherwise of moderate salinity with moderate strontium, magnesium, and calcium ions. Seawater breakthrough has been observed on all of the producer wells resulting in barite (BaSO) scale dominating over all others. This should not however detract from the potential for both celestite (SrSO) and calcite (CaCO) to form. It is clear that the control of water production and scaling potential is absolutely crucial to the field producing to the planned COP: even losing one well to scale will have a dramatic impact on the decline trends and late field life.
Conventionally, scale mitigation is achieved using chemical inhibitors either by squeeze treatment into the reservoir or continuous injection. However, with new fields encountering increasingly more challenging environments, or when the economic impact of chemical intervention by squeeze treatment is large (e.g. subsea fields with poor bullhead chemical placement), other methods of scale control such as the use of low sulphate sea water (LSSW), must be considered during the front end engineering and design (FEED) stage of a field development. Nevertheless, for conventional sulphate reduction packages (SRP's) that reduce the sulphate concentration in the injected sea water typically towards 40 - 50 ppm, there remains a residual scaling risk and the requirement for periodic squeeze treatments.
Previous work reported at the 2004 SPE Oilfield Scale symposium (SPE 87465) examined the level of sulphate reduction required to mitigate the requirement for even periodic squeeze treatments against barium sulphate scale.This showed that sulphate levels of 20 ppm were required in order to prevent scale formation under down hole production conditions, although it was also demonstrated that thermodynamically the system remained oversaturated with barium sulphate.
This paper expands considerably on this preliminary "field specific" case and examines the impact of LSSW on the scaling kinetics across a broad range of formation water compositions (barium ranging from 150 ppm to 650 ppm) and at temperatures between 80ºC and 120ºC. The paper therefore investigates the relationship between scaling kinetics and thermodynamics in relatively mild scaling environments and illustrates that whereas extremely low levels of sulphate would be required to completely prevent scale from a thermodynamic viewpoint, the kinetics of scale formation may prevent scale precipitation under down hole production conditions, with additional continuous injection inhibitor applied at wellheads to protect flow lines etc.In summary, this paper presents results from an extensive series of long term dynamic flow and pseudo static performance tests designed to determine the relative impact of thermodynamics and kinetics on the residual barium sulphate scaling risks associated with the injection of LSSW for pressure support.
However, zinc sulfide (ZnS) and lead sulfide (PbS) are less common, and require a slightly different approach to treatment. It has been suggested in the past that a special type of "novel" scale inhibitor is best for inhibiting zinc sulfide and lead sulfide scales
The Kestrel field is an 8-km sub-sea tie-back to the Tern platform in the Northern North Sea, and consists of two gas-lifted (GL) producers supported by a single injection well. Seawater broke through at P1 in the first half of 2004, and after several months at low seawater fractions a very rapid decline observed in the downhole pressure gauge was inferred to be caused by BaSO scale. Although the scaling tendency was predicted to be relatively low in this Brent-type reservoir ([Ba[2+]] < 30 mg/l in the formation water), other flow assurance causes, including sand production and liner collapse, were deemed much less likely.
The most cost-effective manner to confirm the inference of scale, as well as to recover lost productivity and prevent further deterioration in P1, was deemed to be a scale dissolver treatment deployed through the sub-sea GL line, via the cross-over valve and into the well, followed by an inhibitor squeeze, similarly deployed. The rationale was that even partial recovery of productivity by the dissolver and/or arrest of further decline by the squeeze should confirm scale as the culprit. Although successful GL-line-deployed inhibitor squeeze had been reported earlier using a non-aqueous package, this was the first using conventional aqueous chemicals, as well as being the first deployed together with a scale solvent. Deployment of a solvent along the methanol line, reported elsewhere, was precluded in Kestrel by the small umbilical diameter and materials constraints. The main challenges in both Kestrel treatments included control of the fluid fronts, compatibility with the materials in the GL line, and prevention of hydrate formation, both at the start of the treatment and upon re-commencement of gas-lift injection.
We report how these challenges were met, and how GL-deployed treatments recovered productivity on P1 and demonstrated that scaling in the field could be managed in this manner in the future.
Introduction and background
The Kestrel Field is a Middle Jurassic Brent Group oil accumulation some 8 km east of the Tern platform in the Northern North Sea (Figure 1). It was discovered in 1997 and first production was in 2001, from 2 almost vertical wells - P1 and P2 - tied back to the Tern via a single "daisy-chained" sub-sea flowline. Secondary recovery via seawater injection was started in late 2002 via a single injection well.
The scaling tendency in the production wells for both carbonate and sulphate scales was predicted to be relatively mild by analogy with other Brent-type formation waters. Nevertheless, some degree of carbonate scaling was expected downstream of the bubble point, possibly exacerbated by the gas-lift injection, and a low but significant sulphate tendency was expected upon seawater breakthrough, typically, at seawater fractions of 3 - 70 %. These predictions were based upon using the composition of Tern formation water as an analogue (Table 1), because no Kestrel water sample was available during project design. The sulphate-scaling tendency as a function of seawater fraction is presented in Figure 2 for typical Kestrel bottom-hole conditions of 104 °C / 200 bar.
In July 2004 a decline was observed in overall production concomitant with a reduction in the THP of P1 and a very rapid decline in its downhole pressure, measured by a gauge located ~ 500 m above the top of perforations (Figure 3). The water cut of this well had been steadily rising since initial water breakthrough in September 2003, and was 56 % by July 2004. As sand had been observed in the separator into whichboth Kestrel and Tern fluids flow, gradual filling of the producing interval of the well with sand was thought to be a possible cause, albeit unlikely. However, beaning back the well to alleviate sand production had no significant effect on the rate of decline of the downhole pressure (Figure 3), and so P1 was shut in. Just before shutting in the well, the combined production from P1 and P2 had dropped to around 70 % of its value before the observed decline.
This paper was prepared for presentation at the SPE International Symposium on Oilfield Scale held in Aberdeen, United Kingdom, 11-12 May 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Abstract Two of 19 wells were lost to carbonate scale in a hightemperature gas condensate field with commingled production. The problem was identified as tubing plugging.