Abstract This paper describes results from a series of comparative core floods and static compatibility tests examining the differences in laboratory test procedure, scale inhibitor (SI) returns and modeling approaches for non-aqueous and aqueous scale inhibitor treatments. Two types of nonaqueous system, one ethylene glycol based and two oil soluble products each containing penta-phosphonate scale inhibitors, were investigated. Detailed compatibility and injectivity tests were carried out before core flooding and special consideration was required in the treatment process due to their hydrophobic property. To understand the scale inhibitor transport and retention mechanisms for these nonaqueous products, comparisons were made with the relevant aqueous applications in terms of scale inhibitor return performance, flow back permeability, possible formation damage and wettability conditions which might account for any post-treatment changes. In addition, possible approaches to mathematically modeling these core floods were studied. This paper will focus on the application of a partitioning model in a standard reservoir simulator. An alternative twophase mathematical model for such systems, which includes both inter-phase partitioning and adsorption has been described in detail in another recent publication. 1 All core floods were performed using outcrop Clashach sandstone material rather than reservoir cores, and hence the advantages of deploying non-aqueous treatments over the conventional aqueous treatments would not be significant. However, the experimental and modeling results help to capture the features of these non-aqueous systems in an understandable way. Results confirmed the existence of complicated phase behavior during the core floods using two oil soluble products. Examination of the core after flooding using an environmental scanning electron microscope (ESEM) indicated decreased water wetness following the two oil soluble scale inhibitor treatments compared with the aqueous treatment. Numerical modeling results show that the behaviour of this system is most consistent with the assumption that the SI in the non-aqueous system is only slightly soluble in the oil phase during the oil post flush.

Abstract Due to the increased cost of scale management in subsea compared to platform or onshore fields, and because of the more limited opportunities for interventions, it is becoming increasingly important to carry out a risk analysis process for scale management as early as possible in the field development plan. This process involves identifying the potential scale risks, and analysing and comparing the options available for managing those risks. This paper discusses how this risk analysis process should be carried out, with a strong emphasis on the need to integrate all the available production chemistry and reservoir engineering data. To demonstrate this process, an example from a development complex, which lies in >400 m (>1300 ft) water depths offshore West Africa, is used. The process has involved the following steps: Analysis of available brine samples to identify maximum scaling potential. Laboratory testing of available scale inhibitors to identify chemistry best suited to this system. Study of analogue fields to identify scaling risks in these fields, and how these risks have been managed, with implications for fields currently being studied. Modification of full field reservoir simulation model to predict seawater breakthrough and duration of seawater production, to identify when, for how long, and using how much inhibitor the wells would require squeeze treatments to control scale. This process involves using flow profiles derived from the reservoir simulation model, and applying them in a near well squeeze simulator to predict treatment performance to minimum inhibitor concentration measured from laboratory studies. Well-by-well analysis of predicted seawater production profiles and total water production rates to identify potential for correct placement of inhibitor by bullhead treatments in zones at risk of scale deposition. Modification of reservoir model to study impact of in situ scale deposition on brine chemistry at the production wells, and revision of requirements for inhibitor squeeze treatments Economic analysis of options available for scale management, comparing sulphate reduction with inhibitor squeezing, based on treatments specifications identified above. The result of this process in the reservoirs in question, which have a moderate to severe scaling tendency, has been to demonstrate that inhibitor placement by bullheading would result in satisfactory placement for all wells. If the assumption is made that no scale deposition takes place in the reservoir, then sulphate reduction becomes a viable option, due to the requirement for regular treatments and relatively high chemical concentrations required. However, taking into account cation losses due to scale deposition deep within the reservoir, the requirements for chemical treatments reduces and squeezing becomes the preferred option. From the simulation models, differences between the reservoirs concerned in terms of the contribution aquifer waters make to scale control were identified, with some wells at much higher risk than others due to the volumes of potentially scaling brines that are expected to be produced. This paper clearly demonstrates that a cross discipline approach using reservoir engineering, production chemistry and completion engineering can lead to a more complete assessment of the scale risk and the correct economic selection of the control program.

Abstract Yukos Oil Company is the second largest oil production company in Russia, and produces 1.2 million barrels daily, with > 60% of this coming from fields in W. Siberia. Base oil and gas production units are located in the European part of Russia (OAO Samaraneftegaz) and W. Siberia (OAO Yuganskneftegaz and OAO Tomskneft VNK) [1]. This production comes from a variety of fields, and it is common for these fields to produce at significant water cuts. Produced water leads to several production and cleanup problems (since it is also re-injected), one of these being the problem of mineral scale. The most common scale is calcium carbonate and this is found in both mild and more severe scaling cases. Sulfate deposits are present too in minimal amounts. However, a feature of the W. Siberian reservoirs is that they have many thousands of wells. Therefore, although the technical problem of treating a single well may not be large, the approach and logistics to protect such a large number of wells is a significant challenge. In this paper we survey the problems of scale in these W. Siberian fields and we outline how Yukos has approached this challenge. Introduction Two production units, OAO Tomskneft and OAO Yuganskneftegaz, carry out the main oil production in Western Siberia on the territory where Yukos has licenses. Fig.1 shows the geographical placement of Yukos's main production and refining units. A brief description of them is presented below. OAO Tomskneft VNK. OAO Tomskneft VNK is the principal Production Association of Yukos subsidiary OAO "Vostochnaya nefteyanaya kompanya", also known as VNK or the Eastern Oil Company. Established in 1966, Tomskneft VNK has produced more than 2 billion barrels of oil since it began its operations. 21 fields are currently under development or in production. Tomskneft VNK operates in the remote western part of the Tomsk Region in Western Siberia. Some of its more unusual assets include its own fleet of river barges and approximately 1,000 kilometers of service roads. Since over 70% of its recoverable reserves fall into the "difficult recovery" category, Tomskneft VNK has introduced advanced technologies for horizontal drilling and deep hydraulic fracturing of formations. It has also begun to acquire additional licenses for the development of several new areas in the Tomsk Region. At present there are 1880 production and 840 injection wells in operation. The average oil rate is 170 bbl/day, and the average water cut is 65%. OAO Yuganskneftegaz. OAO Yuganskneftegaz is the Yukos Oil Company's largest Production Association - and the second largest in all of Russia. Yuganskneftegaz, located in the Khanty-Mansi Autonomous Area of Western Siberia, first began operations in 1964, and has produced over 9 billion barrels of crude to date. At present, Yuganskneftegaz manages 29 fields, the largest of these being Priobskoye, Prirazlomnoye, Mamontovskoye, Malo-Balykskoye and Salymskoye. The Priobskoye field is unique as to its geological structure. Recoverable reserves are estimated at 3.01 billion barrels. Prirazlomnoye has 2 billion barrels reserves; a three-dimensional seismic survey of the field has revealed the existence of promising areas that could significantly increase production there. In order to improve well operation, Yuganskneftegaz is introducing hydraulic fracturing and implementing a program to increase efficiency and reliability at its production sites. The program includes improving the power supply system, purchasing additional up-to-date well equipment, and establishing a network of production supervisors. At present there are 6000 production and 2300 injection wells in operation. The average oil rate is 169 bbl/day, and the average water cut is 71%. OAO Tomskneft VNK. OAO Tomskneft VNK is the principal Production Association of Yukos subsidiary OAO "Vostochnaya nefteyanaya kompanya", also known as VNK or the Eastern Oil Company. Established in 1966, Tomskneft VNK has produced more than 2 billion barrels of oil since it began its operations. 21 fields are currently under development or in production. Tomskneft VNK operates in the remote western part of the Tomsk Region in Western Siberia. Some of its more unusual assets include its own fleet of river barges and approximately 1,000 kilometers of service roads. Since over 70% of its recoverable reserves fall into the "difficult recovery" category, Tomskneft VNK has introduced advanced technologies for horizontal drilling and deep hydraulic fracturing of formations. It has also begun to acquire additional licenses for the development of several new areas in the Tomsk Region. At present there are 1880 production and 840 injection wells in operation. The average oil rate is 170 bbl/day, and the average water cut is 65%. OAO Yuganskneftegaz. OAO Yuganskneftegaz is the Yukos Oil Company's largest Production Association - and the second largest in all of Russia. Yuganskneftegaz, located in the Khanty-Mansi Autonomous Area of Western Siberia, first began operations in 1964, and has produced over 9 billion barrels of crude to date. At present, Yuganskneftegaz manages 29 fields, the largest of these being Priobskoye, Prirazlomnoye, Mamontovskoye, Malo-Balykskoye and Salymskoye. The Priobskoye field is unique as to its geological structure. Recoverable reserves are estimated at 3.01 billion barrels. Prirazlomnoye has 2 billion barrels reserves; a three-dimensional seismic survey of the field has revealed the existence of promising areas that could significantly increase production there. In order to improve well operation, Yuganskneftegaz is introducing hydraulic fracturing and implementing a program to increase efficiency and reliability at its production sites. The program includes improving the power supply system, purchasing additional up-to-date well equipment, and establishing a network of production supervisors. At present there are 6000 production and 2300 injection wells in operation. The average oil rate is 169 bbl/day, and the average water cut is 71%.

Abstract The injection of seawater into oilfield reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature, operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. However, the current drive within the North Sea to reduce the environmental burden of production chemicals and to reduce oil discharge to the environment has focused attention on the challenge of produced water management and has introduced new challenges for scale management involving produced water re-injection. This paper will outline the risk assessment process required prior to undertaking produced water re-injection. The factors that will be considered are the location of scale deposition around fractured and unfractured injection wells, formation damage potential and impact, and retardation effects on injected scale inhibitors. The paper will draw upon computer modelling techniques, laboratory generated coreflood data, and field results that will demonstrate the impact of the following factors on long term water injectivity: viz, scaling tendency, suspended solids content, suspended oil content, injection temperature, reservoir type, and completion type. Furthermore, scale control measures currently being employed (e.g., scale inhibition, hydraulic fracturing, drag reduction, and solvent cleaning) will be assessed and reviewed against the risks identified. Finally, this paper will outline in detail the particular scaling issues associated with produced water re-injection for both platform and subsea facilities. Introduction Increased environmental concern for the effects of produced water discharges is increasingly encouraging operators to dispose of produced water by re-injection either into the oil-bearing formation or into a specially selected aquifer. In addition to the environmental benefits of produced water re-injection (PWRI), there are other potential benefits including making cost, space and weight savings through the optimisation of water treatment facilities and produced water re-injection system throughout the life of a field. Re-injection of produced water is performed in several locations around the world. BP, for example, was an early adopter of the technology with re-injection schemes in Prudhoe Bay and the Forties Field in the early 1990's and the Ula Field in the Norwegian sector of the North Sea from the mid-1990's 1–4 . Today, BP has a corporate goal of eliminating all discharges to the sea by 2004. Early experience of PWRI was focused on individual wells and did not include the co-mingling of produced water with seawater. With the move to full-field PWRI and the requirement to maintain voidage replacement, there is an increasing requirement to either co-mingle the fluids prior to injection or to inject both seawater and produced water into the same reservoir but via separate wells. Such practices introduce scale formation risks. These can be both calcium carbonate formation arising from the produced water itself and sulphate scales arising from the co-mingling of barium, strontium, and calcium containing produced waters with seawater. Clearly, the formation of such scales poses a risk to the topside injection system, the injection well itself, and finally the near-wellbore. Managing these risks is critically important to effective field management (in terms of being able to maintain adequate water injection) and to being able to maintain a zero water discharge commitment. This paper addresses methods of assessing the risk that scale poses to PWRI schemes and outlines the various management options that are available. The overall process and methodology is illustrated by field examples from the North Sea Basin. Risk Assessment Field Experience Under favourable operating conditions, the risk of scale damage to produced water re-injection wells should not be significant. However, it is possible that under certain injection conditions rapid build-up of scale could lead to complete loss of injectivity. Avoiding such a catastrophic scenario is the objective of the risk assessment process. The preliminary step is to study field case histories. This is then followed by the procedure of calculating potential scaling scenarios using scale prediction codes and fluid flow simulations to evaluate the risk. Field Experience Under favourable operating conditions, the risk of scale damage to produced water re-injection wells should not be significant. However, it is possible that under certain injection conditions rapid build-up of scale could lead to complete loss of injectivity. Avoiding such a catastrophic scenario is the objective of the risk assessment process. The preliminary step is to study field case histories. This is then followed by the procedure of calculating potential scaling scenarios using scale prediction codes and fluid flow simulations to evaluate the risk.

Abstract A number of mature waterflooded fields, such as Brent in the North Sea and others elsewhere are undergoing tertiary recovery by depressurisation. Pressure depletion is achieved by stopping water injection and by producing from the aquifer as well as the hydrocarbon bearing strata. Previously bypassed oil rims and trapped oil and gas are then released. This paper discusses how mineral scale deposition is affected by the change in reservoir conditions that occur during blow down. Pressure maintenance by waterflooding may prevent reservoir fluids from dropping below the CO 2 bubble point until they are in the production string. However, as a result of depressurisation, the CO 2 bubble point will move down the tubing and into the formation. Calcite scales form as a result of the increase in pH that occurs when CO 2 is evolved, and thus the calcite scaling problem will migrate into the near production well formation during depressurisation. The balance of oil-water and gas-oil capillary pressures changes with pressure depletion, resulting in the mobilisation of previously trapped form ation brines. Waterflooding also results in large volumes of seawater being injected into the oil bearing strata. During depressurisation, this seawater is back produced through the former injectors. Depending on the strength of the aquifer, formation brine may also be produced. If these brines are incompatible, then mixing in the wellbore or near well formation will result in sulphate scale damage. Calculations demonstrate that co-production of aquifer and injected brines may occur for more extensive periods at the critical mixing ratios than would be typical of conventional production scenarios. Former injection wells will produce at near 100% watercuts, with the result that large volumes of water need to be protected. Calculations of reservoir temp eratures and the scaling potentials show that the problem is exacerbated by the fact that during water injection these zones will have been cooled. Introduction A number of mature waterflooded fields, such as Brent in the North Sea and others elsewhere are undergoing tertiary recovery by depressurisation 1-5 . Pressure depletion is achieved by stopping water injection and by producing from the aquifer as well as the hydrocarbon bearing strata. Previously bypassed oil rims and trapped oil and gas are then released. Since early 1998, the Brent field has been undergoing depressurisation to recover an additional 1.5 Tscf of gas and 34 MMstb of oil, extending the field life by 5-10 years. The platform topsides have been redeveloped and refurbished, with process facilities for low-pressure operations installed, at a cost of over US$ 2 billion 4 . The plan is to depressurise the reservoir in order to release solution gas from the bypassed (unswept) and remaining (swept or residual) oil, and to produce the gas, once it has migrat ed to the crest of the structure. Implementing the depressurisation plan is more activity and labour intensive than in a conventional development. The criteria to be managed include gas production and availability, oil production, water production, gas injection, pressure and gas cap size in each reservoir unit and area of the field, gas lift, and ESPs. Maintaining sufficient gross liquid production from the start of depressurisation has necessitated the provision of artificial lift. Gas lift has been installed in a number of wells, while ESPs have been used in low GOR and water producing wells to increase lift. As the reservoir pressure declines there is a transition from gas lift to high rate ESPs to enhance voidage. A number of infill wells have been located in the water-flooded oil leg to gain additional oil production, albeit at high water-cut and with a potential reduction in gross rate.

Abstract Previous work has demonstrated how and where the mixing of incompatible brines occurs in waterflooded reservoirs, and what the impact would be on scale prevention strategies in terms of timing and placement of squeeze treatments. This paper extends this work, by modelling the resulting in-situ deposition process. The location of maximum scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir geometry (1D, 2D areal, 2D vertical, 3D), well geometry (location and orientation within field and with respect to other wells and the aquifer), and reaction rate (ranging from no precipitation to equilibrium). In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs in the immediate vicinity of the production wellbore, and therefore low produced cation concentrations indicate inadequate squeeze treatments. In systems where water injection is into the aquifer, low cation concentrations may also result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well, but sufficiently far from the wellbore to be unaffected by squeeze treatments, or to have any major impact on productivity. The reaction rate is critical in determining the amount of scale deposition, but even under equilibrium conditions, sufficient concentrations of scaling ions are delivered to the production well to necessitate squeezing the well, although using lower volumes of inhibitor. Once cation concentrations have been reduced, it is predicted that they will never pick up again. This paper also discusses some of the limitations of modelling such systems, which include the determination of the kinetic reaction rates, size of the mixing zone, and the impact on permeability. Although the thermodynamics are fairly well understood, the kinetics are much more difficult. The size of the mixing zone is affected by numerical dispersion, and computationally intensive techniques are required to overcome this problem. Previous experience shows that formation damage factors are very difficult to extrapolate from coreflood data because there is a great difference between the dimensions of the mixing zone in the reservoir and the core plug. Introduction Previously presented work has shown the effect of brine mixing under various flow conditions, both idealised 1,2 (1D, 2D vertical, 2D areal, 3D) and actual reservoir conditions 3,4 (Alba Reservoir, North Sea). For the majority of these calculations a conventional reservoir simulator has been used. The advantages of using a conventional simulator are that a large proportion of waterflooded reservoirs have a field model dataset already available, the addition of tracer tracking to model the propagation of the mixing zone is relatively straightforward to implement, and the results are easy to visualise. This technique is quite powerful for demonstrating the movement of the water front and also the mixing zone relative to the production wells. Even within a given field the behaviour may vary quite markedly, depending on the configuration of neighbouring wells and the reservoir geometry, as was shown in the Alba case 3 .

Abstract This paper brings the discussion on brine mixing initiated at the 1999 SPE Symposium on Oilfield Scale full circle, and suggests that different scaling regimes may exist in any given reservoir that should impact the scale management strategy. The initial paper by White et al. (1999) identified lower than expected barium levels in many wells in the Alba field, and raised the question of where scale deposition is occurring. A follow-up paper at the same meeting the following year by Mackay and Sorbie (2000) identified from a theoretical standpoint where brine mixing should be expected, and suggested that significant scale deposition may occur deep within the reservoir, particularly where a large proportion of injected water sweeps through the aquifer. The current paper seeks to apply that theoretical analysis to the Alba field, on a well-by-well basis, to establish whether diagnostic tests can identify which wells should be treated conventionally, and which require special attention. Firstly, production data and produced brine compositions are analysed to identify any recurring patterns. Wells are then classified and grouped according to various types based on this analysis. Well properties such as location within the reservoir and orientation to the flood front are then compared to identify whether they can be used to give a similar grouping of wells. Three principal zones are identified, with position relative to the injection wells and the aquifer identified as key parameters. Secondly, the flow patterns around each well are studied using the existing reservoir flow model. Modelling the dynamic mixing patterns throws further light on the differences between the zones, with scale dropout predicted in the aquifer in some areas, and in the oil-leg in others. Recommendations are made regarding the treatment of existing wells and the optimum positioning, from a scale prevention perspective, of any new wells. Introduction Sulphate scale deposition is a common problem in reservoirs where injected seawater mixes with aquifer brines 1,2 . For reasons that will be explained in the next section, the problem is most severe in and around the production well bores, and can cause considerable disruption to hydrocarbon production after water breakthrough. To deal with the problem two general tasks must be performed. Firstly, the quantity and type of scale must be identified, together with the location and timing of the deposition. Secondly, a suitable removal and/or prevention strategy must be designed and implemented. Both of these tasks require reservoir and laboratory data, and field experience is also a vital component in ensuring successful treatment. Both tasks are routinely assisted by application of appropriate modelling tools 3 . The use of reservoir simulators to predict the timing and location of water breakthrough, and the application of scale prediction codes to identify the scaling regimes, have both been discussed previously 4–9 . In addition, models are routinely used in chemical scale inhibitor selection studies and to optimize inhibitor squeeze treatments 10 . The topic of this paper is not so much the design of scale prevention treatments, although the findings have a bearing on this, but on identifying scale deposition regimes throughout an actual reservoir system. To do this produced brine chemistry data and field fluid flow modelling have been analysed on a well-by-well and field-wide basis for the Alba Field in the North Sea. The evidence of both the produced brine chemistries and the flow calculations is that scale is depositing deep within the reservoir. However, the extent and impact of this deposition varies throughout the reservoir. Three regimes are identified, where the nature of the scaling problem at individual production wells can be related to the flow characteristics in that locality. Important factors are shown to be the proximity of injection wells and the proximity and extent of the aquifer.

Abstract Various general-purpose software packages can be used to optimise the design of scale inhibitor squeeze treatments. However, the versatility and cost of these codes typically makes them cumbersome and expensive to use for optimising routine squeeze treatments. Conventional treatments should be modelled using purpose designed squeeze simulators that minimise data entry and facilitate quick extraction of results. However, misapplication of even a fit-for-purpose simulator can lead to incorrect treatment design. This problem is compounded by the fact that squeeze strategies are always being developed and refined, and the software must be developed to keep pace with these changes in technology if it is going to be applied correctly. To deal with these twin issues, this paper will first describe how a squeeze simulator should be correctly applied, and what information may and may not validly be extracted. Potential pitfalls will be highlighted, as well as techniques for optimising the model set-up to ensure that the maximum amount of relevant data is utilised. Experience gained from use of the SQUEEZE V software for modelling core floods, single and multi-layer radial well models will be discussed, and the rationale for making certain decisions when building a model will be highlighted. Secondly, new features being introduced into this code are discussed, together with the impact these may have. The new facilities include two-phase flow, with the potential for component transport in the oleic phase, and full crossflow within the formation in addition to the well. Finally, the paper will present planned future developments that should improve the applicability and scope of the code, without increasing the difficulty of use unduly. Introduction SQUEEZE V is a purpose built simulator that is routinely used to assist with: Scale inhibitor selection, and The design of squeeze treatments. Scale inhibitor selection usually involves various laboratory tests to evaluate inhibitor compatibility with the formation rock and brine, thermal stability, retention in the formation, scale prevention efficiency, compatibility with other production chemicals, etc. Inhibitor retention and formation damage are usually tested by means of a core flood. If measured, the effluent concentrations during postflush can be used in SQUEEZE V to derive an inhibitor-rock interaction function, or isotherm. Once derived, the isotherm may be used to evaluate how the inhibitor will perform in a given well system. The performance of different inhibitors may be compared by using their respective isotherms to model the same basic treatment. The inhibitor that gives the longest squeeze life to its own MIC will usually be selected, everything else being equal (eg formation damage potential, compatibility with brines and other chemicals, etc). The design of a squeeze treatment may be optimised using the SQUEEZE V model. Once an inhibitor has been selected, and the isotherm derived, injection of inhibitor into the formation round the well bore may be modelled. The parameters that the engineer can control during the treatment may then be varied to assess their impact on the success or otherwise of the treatment. SQUEEZE V is best used to perform a sensitivity study of the parameters under the engineer's control, rather than to pin down an exact squeeze life for the treatment. The accuracy of the model can be greatly enhanced by use of reservoir engineering data, such as the calculated layer flow rates during injection and production. Sensitivity to injection rate can thus be tested, and the impact of varying water production rates during the expected lifetime of the treatment may also be assessed. The SQUEEZE model is being upgraded to include two-phase flow, with a view to modelling non-aqueous scale inhibitors, and it will perform the pressure calculations in the reservoir that will allow crossflow to be fully accounted for. This will allow a chemical diversion model to be developed.

Abstract In recent years, a number of new HT/HP reservoirs have been developed in the North Sea. The Shearwater reservoir is a gas condensate producer located in Block 22/30 in the North Sea. This reservoir has very harsh downhole conditions as follows: T ~ 370°F, P < 13,000 psi, brine TDS > 250,000 mg/l and is therefore classed as a HP/HT/HS reservoir. Significant downhole carbonate scale ([Ca 2+ ] ~ 20,000 ppm; [Bicarb] ~ 560 ppm) is expected in the wellbore and near wellbore formation area initially at low GWR (GWR < 0.05) with the main mechanism being evaporation from the low volume brine phase into the high volume gas phase. As a result, downhole squeeze scale inhibitor treatments will be required at a very early stage of production. In a previous paper (SPE 60217), presented at the 2000 Scale Symposium, we presented results from a detailed screening study, based largely on bulk experiments (thermal stability, compatibility and performance), to select appropriate chemicals for potential application in this reservoir. Five products were selected which covered a range of generic chemical types including thermally stable phosphonates (HMDP), sulphonated polymers (PVS, S-Co) and phosphorous containing co-polymers (P-SCo). Further work involving a series of high temperature core flooding experiments conducted at 374°F (190°C) have now been completed on the various pre-selected products. In addition to monitoring inhibitor return profiles, the performance of the released inhibitor species was also examined, with some surprising results. The results from these tests have significant implications on the selection of products for downhole application under such harsh conditions. Results are presented in the following areas: Comparative inhibitor retention and return characteristics Comparative field application modelling using SQUEEZE V software Implications of adsorption on the thermal stability of the pre-selected products. Results in this study demonstrate that the rock surface interaction of certain pre-selected chemical species in core flood experiments can alter their performance (as a result of thermal degradation), which was not recorded in the initial static thermal stability tests. This is not in accordance with previously held opinions that adsorption onto rock substrates increases the thermal stability of scale inhibitor products.

Abstract Although waterflooding is a common method for increasing oil recovery, certain production problems may arise after water breakthrough. In addition to affecting oil recovery, these problems may also have an adverse impact on the environment. One particular production problem is mineral scale formation due to mixing of incompatible brines. For example, barium sulphate formation in the production well and tubulars occurs in many oilfields when sulphate rich injection water (usually seawater) mixes with barium rich formation water close to or in the wellbore. Understanding where the scale forms is important when attempting to prevent it damaging productivity. However, there is some field evidence which suggests that scale deposition deep within the reservoir may occur without having any adverse effect on oil recovery. This paper addresses the two related issues of where sulphate scales form, and whether any operator action is required where wells are producing lower concentrations of scaling ions than would be expected if scale formation was completely inhibited. These issues were raised by two papers presented at the 1 st SPE International Symposium on Oilfield Scale in January 1999, and it was the ensuing discussion which initiated the present study. All of the principal mechanisms of brine mixing in waterflood displacements are considered and modelled. This leads to a fuller understanding of where - and to what extent -brine mixing will occur within the reservoir. As a consequence, we may address the questions of why scale deposition deep within the reservoir may in certain circumstances occur, while in other situations it is probably very limited. It is demonstrated that, although connate water in the oil zone is mobilised by injected water, typically little mixing would be expected far from the wellbore. Conversely, as the different brine types, which have retained the scaling ions, approach the wellbore, mixing and scale deposition are to be expected. Mixing in the aquifer where brine mobility can be much higher, however, may result in lower than expected ion concentrations. The reduced ion concentrations may be caused by scale dropout, or by mixing of formation brines with different compositions, or by a combination of both mechanisms. In either case, modelling of such processes has confirmed that they are possible explanations for low barium levels. The impact of scale dropout deep in the reservoir on the design of inhibitor squeeze treatments is discussed. Introduction Modelling tools are routinely applied in the design of a scale prevention strategy 1,2 in order to obtain a better understanding of the system to be treated, and to minimise the risks in the provision of flow assurance. For example, there are five simulation techniques that can be used to optimise the design of an inhibitor squeeze treatment 3 . These are used to: Predict water production. Reservoir simulation models are used to predict when, where and what type of water production should be expected. Predict scaling tendency. Scale prediction models can calculate the type and mass of scale that will be deposited. Derive inhibitor-rock interaction table. A core flood model can derive the adsorption isotherm that relates the mass of inhibitor adsorbed to the concentration in solution. Predict inhibitor placement. Reservoir or near-well models can predict chemical placement under bullheading, or with mechanical or chemical diversion. Placement of chemical diverter can also be modelled. Optimise treatment. Near-wellbore or full-field models can calculate squeeze lifetimes, and are used to design and optimise treatments by sensitivity analysis.