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Collaborating Authors
SPE International Oilfield Scale Symposium
Abstract A major phenomenon altering well productivity is increasing water production. In addition to raising energy consumption, higher water production leads to phenomena such as mineral and organic scaling, which may temporarily or even permanently alter the whole flow assurance chain. The build-up of scale inside well bore can smother a productive well within 24 hours, causing millions of dollars in damage every year. A project was carried out to review and to evaluate new techniques and tools developed for scale treatments in order to find an appropriate tool, at least deployed with wireline rather than with coiled tubing (CT) to overcome the adverse scale problems encountered in most of the fields. This paper presents results of this evaluation and shows the advantages and disadvantages of different tools for scale removal process. Solid blasters, deployed with CT, have proved to be efficient in removing most of the scales but it is costly as well as inapplicable to wellbore and near-wellbore. Tools using fluidic oscillator technology is not that expensive, however they are not strong enough to treat very hard scales like barium sulphate. In addition, these tools have great standoff distances and are deployed with CT. String shots, wireline-deployed, are good for short intervals, thin layers of scales. Recent techniques, which use acoustic waves to clean the near wellbore damage are not good tools to be applied for tubing and casing scale depositions since they have only proved to have the ability to remove fines and soft materials like mud cakes from near wellbore region. Introduction Declining oil production is of major concern in the oil industry. This decrease is often due to scale deposition. Unfortunately, this is an issue becoming more and more important as the oil reservoirs are depleted and the number of EOR projects including water and gas injection goes high. As the oil reserves decreases, the conditions of production get more severe, favoring the formation of scale. Scale is defined as the secondary deposit of mainly inorganic chemical compounds caused by the presence or flow of fluids in a system at least partially man-made1. In other words, it is an assemblage of deposits that cake perforations, casing, production tubing, valves, pumps and downhole completion equipment, thereby clogging the wellbore and preventing fluid flow. Scale can be deposited all along water paths from injectors through the reservoir to surface equipment. Most scale found in oil fields forms either by direct precipitation from the water that occurs naturally in reservoir rocks, or as a result of produced water becoming oversaturated with scale components when two incompatible waters meet downhole. For situations of injected sea water breakthrough the problem is especially great as the growth is often barium, or strontium sulphate, both of which are almost completely insoluble. The direct cost of removing scale from one well can be very high, and the cost of deferred production even higher. Although many tools using different cleaning technologies have been developed, none of them has proved to be the perfect solution to be applied in any severe cases. Actually each tool has its own pros and cons thus having limited range of applicability. Before recent developments in scale-removal technology, operators with hard scale problems in their production tubing were often forced to shut down production, move in workover rigs to pull the damaged tubing out of the well, and either treat for scale at the surface or replace the tubing. One of the earliest scale-removal methods was an outgrowth of the use of explosives to rattle pipe and break off brittle scale. Explosives provided high-energy impact loads that could remove scale, but often damaged tubular and cement[2].
Abstract Interpretation of produced water analyses is a relatively inexpensive method of obtaining a wide range of information that can be used to aid scale management, constrain the reservoir model, provide information on barriers to flow and zones of connectivity in the reservoir, and identify zones of water production in wells. In this paper we report on the interpretation of produced water analyses to help understand why unusual low salinity water was produced from well Z3, a sub-sea well in the Birch Field with two production zones (Brae Conglomerate and Ryazanian Sandstone), when production was re-started in March 2004 after a three-year shut-in period. In this case, of particular interest were the implications for future scale management on the well. We have shown that the low salinity water is likely to be formation water from the Ryazanian Sandstone. Production of this water from well Z3 is declining over time, which may reflect the limited extent of the Ryazanian Sandstone, a nearby barrier to flow or calcium carbonate deposition adjacent to the well during pressure drawdown. Future water production from well Z3 is expected to be dominated by production from the Brae Conglomerate with production from the Ryazanian Sandstone only being important after lengthy shut-in periods. Current squeeze treatments are based on pre-development scaling predictions and have been designed to prevent moderate barite deposition. These treatments are likely to mitigate the mild barite scale deposition predicted to be associated with future production of water from the Brae and Ryazanian intervals. As the future scaling potential is predicted to be much less than originally planned for, the possibility of reducing the current MIC or discontinuing future squeeze treatments is being considered. Further work is required to fully assess the carbonate scaling risk associated with mixing of these waters but there are currently no indications that carbonate scale is forming in the well. This study has demonstrated the value of interpretation of routinely collected produced water analyses in that it helped us understand and act on significant changes in produced water compositions from a sub-sea well without resorting to an expensive well intervention. Introduction Interpretation of produced water analyses is a relatively inexpensive method of obtaining a wide range of information including the time of injection water breakthrough, the proportion of injection water in produced flow, evidence for the presence of barriers to flow and zones of connectivity in the reservoir, the source of produced water, estimated compositions of formation water, evidence for reactions occurring in the reservoir during waterflood, fractions of produced water derived from different production intervals, and evidence for scale deposition in the well[1–6]. Generally, interpretation of produced water analyses has been confined to fields with dry wellheads where samples have been obtained from individual wells, occasionally completed with two or more production zones. Interpretation of produced water analyses from sub-sea fields is more complicated in that many of the samples obtained are usually mixtures of water produced from several different zones in each well, several different wells and sometimes more than one field.
- Europe > United Kingdom > North Sea > Central North Sea (0.85)
- North America > Canada > Alberta > Minburn County No. 27 (0.62)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Valanginian (1.00)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous > Berriasian (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.93)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/12a > Larch Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/12a > Birch Field (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Simulating Calcium Naphthenate Formation and Mitigation Under Laboratory Conditions
Graham, Gordon M. (Scaled Solutions Limited) | Melvin, Keith Buchan (Talisman Energy UK Limited) | Gabb, Alexander Emil (British Gas Intl.) | Haider, Faheem (BG Group plc) | Williams, Helen (Scaled Solutions Limited) | Dyer, Sarah (Scaled Solutions Limited) | cummine, Craig (Talisman Oil)
Abstract A laboratory methodology has been developed to better simulate calcium naphthenate formation and evaluate chemical inhibition measures. Detailed ongoing field experience data and related samples have been used in support of the lab rig design and protocols. Calcium Naphthenates are becoming more recognized as a major flow assurance issue. When occurring in the field operation, significant quantities (typically in tonnes per day) can be formed and the process operation, chemical controls and monitoring procedures are far from straightforward. The ability to accurately predict calcium naphthenate formation and/or replicate field production conditions in the laboratory has been fraught with difficulties. For example conventional "bottle" or "jar" test procedures suffer from severe limitations relating to poor pH control, inefficient mixing, non representative residence times coupled with relatively indirect assessments often indicating fluid compatibility issues rather than identification of naphthenate deposits. Recent work examining both current calcium naphthenate problems in existing facilities and the technical requirement to predict the potential for naphthenate deposits in new fields has led to the design and validation of more appropriate laboratory test equipment. This includes new designs of novel dynamic flow systems and modified autoclave approaches which allow the formation of naphthenate deposits, stable emulsions and soap scales to be assessed directly under laboratory conditions using relatively small volumes of reservoir fluids. The designed equipment is shown to overcome the challenges previously associated with the assessment of calcium naphthenate issues, their mitigation and chemical treatment under laboratory conditions. The ability to simulate naphthenate deposition represents a major step forward in our ability to understand the controlling parameters associated with these complex scales. This paper will describe the novel aspects associated with the laboratory flow rig and other test methods adopted, it will illustrate how the equipment design overcomes the limitations associated with more conventional tests and describe how the results are being used directly to assess the changing naphthenate challenge and its treatment which may be expected throughout a field's lifetime. The composition of solids collected from naphthenate formation tests in the flow rig under different conditions is also presented, thus further validating the effectiveness of the rig design. The paper therefore illustrates how improved equipment design and test protocols can reduce the risks associated with field trials, which have previously been required for optimising treatments against naphthenate deposits. Introduction Although the presence of naphthenic acids in crude oil and their impact on emulsion stability and the formation of sludges, soaps, stabilised emulsions and other production problems have been known for many decades, little direct evidence of calcium naphthenate deposits has been reported until relatively recently. Over the last 10 years[1] the problem of calcium naphthenate deposits has become an increasing problem, especially for fields producing oils which have been subject to biodegradation resulting in relatively low wax contents and high dissolved naphthenic acids. An increasing number of fields especially in areas such as West Africa, the North Sea and Venezuela[1,2,3] have therefore reported problems leading to several literature references over recent years as their formation represents a significant flow assurance issue for several major field developments. Sodium naphthenate sludges have also been observed in Indonesian fields[4–6] in addition to bicarbonate and metal ion stabilised naphthenate sludges. [20] As the solution to a naphthenate problem is often required urgently and as this is a relatively novel area of research, most work to date has focussed on specific fields and the problems encountered in these fields, although some work has progressed over recent years to consider the generic problem and to rationalise and unravel the relative importance of the various factors involved in this complex reaction system (e.g. amount and type of naphthenic acids present in the oil phase, emulsion stability, interface activity, metal cations (particularly Ca and Na), bicarbonate concentration and pH in the brine phase, water cut and system temperature etc.).[7–9,19]
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Ile Formation (0.99)
- (7 more...)
Abstract Chemical Placement for scale inhibitor squeeze and other near wellbore chemical treatments is recognized as a significant challenge in today's ever more complex operating environments. For heterogeneous wells and long reach horizontal wells, various factors (including heterogeneity, crossflow and pressure gradients between non-communicating zones within the well) all contribute to uneven placement in the reservoir. Current methods to circumvent these problems often rely on extremely expensive coiled tubing operations, staged diversion (temporary shut-off) treatments or overdosing some zones to gain placement in other (e.g. low permeability) zones. For other very near wellbore treatments e.g. acid stimulation, a number of self-diverting strategies have been applied in field treatments with some success. Unfortunately, the properties which make such treatments applicable for acid stimulation may also make them inappropriate for scale squeeze treatments. Other modified lightly viscosified fluids have however been demonstrated to be of significant importance for improving chemical placement thereby reducing the potential for low permeability/high pressure zones being rapidly denuded of chemical during flowback. Critical to our understanding of such a process is the ability to accurately simulate the effectiveness of such treatments in the laboratory and to use the data to build and validate more effective modelling tools to allow field treatments to be designed. The paper examines the potential benefits of using modified injection fluids, including lightly viscosified and shear thinning fluids to aid uniform scale inhibitor placement in complex wells. Laboratory data using dual linear core flood experiments coupled with mathematical modelling are used to describe cases where such fluids are shown to offer benefit for field application and also those where more minimal benefit would be anticipated, such that the risks associated with the use of modified fluids (e.g. potential formation damage and fines mobilization) would outlay the benefits. The paper therefore describes the effective use and interpretation of detailed laboratory core flood data, mathematical modelling and field evidence to describe the benefits associated with the application of modified lightly viscosified shear thinning fluids in scale inhibitor squeeze treatments. INTRODUCTION Chemical placement for scale inhibitor squeeze and other near wellbore chemical treatments is recognized as a significant challenge in today's ever more complex operating environments, especially if effective chemical placement cannot be achieved through conventional bullhead squeeze treatments.[1–8] For heterogeneous wells and long reach horizontal wells, a combination of factors (such as heterogeneity, crossflow and pressure gradients between non-communicating zones within the well) can contribute to uneven placement of a squeeze treatment in the reservoir. This may result in the majority of the squeeze treatment volume being placed in an inappropriate zone in the near-wellbore, which can result in reduced squeeze lifetimes and inadequate scale protection of vulnerable near-wellbore mixing zones. Heterogeneity in the near-wellbore region will obviously affect the placement of a squeeze treatment under permeability control, with most of the volume of a conventional bullhead squeeze being placed in the higher permeability formation. Pressure gradients or crossflow will also influence the placement of an inhibitor slug, with injection being favoured in the lower pressure zones. The presence of crossflow during shut-in can cause a redistribution of the injected slug, resulting in more placement in a lower pressure zone. Other factors such as wellbore friction, layer pressures, the properties of the fluid in place and differences in mobility ratios between different zones also have an impact on chemical placement but will not be considered in this manuscript.
- Europe > Norway (0.67)
- North America > United States > Texas > Harris County > Houston (0.28)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/7 > Nelson Field > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/6a > Nelson Field > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/12a > Nelson Field > Forties Formation (0.99)
- (7 more...)
Abstract Scale formation and well plugging due to the incompatibility of injected wastewaters is a critical field problem in wastewater disposal wells. When different wastewaters are mixed it is necessary to evaluate their compatibility prior to the injection in disposal wells. The individual wastewaters may be quite stable at all system conditions and present no scale problems. However, once they are mixed, reaction between ions dissolved in the individual wastewaters may form insoluble products that cause permeability damage in the vicinity of the wellbore. In this paper, the composition of different wastewaters that were collected from southwest Iranian desalting plants disposal wells were analyzed critically. Laboratory studies as well as field experience has shown that formation damage in wastewater disposal wells may occur mainly due to the conception of Iron Sulfide in the case of mixing a wastewater which contains Iron ions with a wastewater containing H2S. A new correlation is developed estimating the critical concentration of Iron ions, Fe(2+) (ferrous ion), which will stay in solution at various pH values and a wide range of H2S concentration in crude oil desalting plants disposal wastewaters. This correlation eliminates the need for compatibility assessment, which is usually assessed either by solubility calculations or by experimental testing, for water mixtures that contains Iron ions and dissolved H2S. Finally, a real case field problem was analyzed and based on the correlation's results three different potential solutions were recommended for further field trial implementation. Introduction Production of salty wet crude had affected the quality of Iranian crudes and a number of wells had to shut in for lack of treating facilities. The produced water with crude in Iranian oil fields contains salts in the concentration of 150,000 to 220,000 ppm. In almost all cases, the salt is found dissolved in the water that is dispersed in the crude oil. This salt water is present in the crude in the form of emulsion (water-in-oil) and its separation is not an easy task. Application of right technology and installation of proper desalting facilities were required to solve this problem. Therefore, it was decided to install electrostatic desalting plants progressively in Iranian oil fields. By end of 2004 more than 20 plants with a total capacity of 207 Mm3/Day (1.3 MMSTB/Day) of treated crude has been installed. It is expected that production of wet crude raise to 400 Mm3/Day (2.5 MMSTB/Day) in Iran by the year 2007. The performance of the majority of current desalting plants have been tested and found satisfactory. Figure 1 depicts the schematic of typical desalting plants in Iranian oil fields. In the desalting process considerable amount of salt will be removed by addition of comparatively fresh water to the crude; this addition of fresh water dilutes the original brine so that the salt content of the water that remains after treatment is within acceptable limits [2, 4]. The desalting process is undoubtedly associated with generation of considerable amount of wastewater that needs to be disposed properly. Its volume is typically about 15% of the crude oil desalting plant capacity, consists of 10% associated formation water and 5% of added wash water. The wastewater processed through wastewater treating system before it is injected into disposal wells. The wastewater treating system consists of a skimmer tank, API gravity separator, filter, and disposal tank. Different crude oils bearing different formation waters are desalted in the Iranian desalting plants resulting in production of different wastewaters compositions. When different wastewaters are mixed it is necessary to evaluate their compatibility prior to the injection in the disposal wells. One of the primary causes of scale formation and injection well plugging is mixing two or more wastewaters which are incompatible. The individual wastewaters may be quite stable at all system conditions and present no scale problems. However, once they are mixed, reaction between ions dissolved in the individual wastewaters may form insoluble products that cause permeability damage in the vicinity of the wellbore. Depending on the amounts of each constituent present, the pH, temperature, and the ratio in which the two waters are mixed, you might expect any or all of the following precipitates to result: Calcium carbonate, calcium sulfate, barium sulfate or Iron Sulfide.
- North America > United States > Texas (0.47)
- Asia > Middle East > Iran > Khuzestan (0.21)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.55)
Abstract A long-term study of produced water chemistry from a North Sea field was used to investigate the mechanisms of water mixing and water-rock interaction in the reservoir. Seawater flooding has continued throughout much of the production life. Detailed repeated sampling of the produced water was undertaken and has produced an extensive dataset, yielding information on water chemistry variations in space and time. The dataset documents both fluid mixing in the field and the physical, chemical and thermodynamic response of the system to the injection of seawater. Analysis of the data establishes the nature of the controls on the composition of the scale-prone formation water, and enables an in-depth look at the fluid-rock interactions occurring in the reservoir during a waterflood. Changes in produced-water chloride concentration through time reflect changing proportions of injected seawater and formation-water, revealing differing patterns of injected-water breakthrough over the field. However, parallel changes in the concentrations of less conservative fluid components provide evidence of fluid-mineral interactions that occurred in the reservoir on the timescale of the waterflood. For example, calcium is enriched in the produced fluid relative to a linear mixture of original formation-water and seawater, while magnesium is depleted, probably reflecting dolomitisation of calcite and growth of clay. Barium and sulphate are strongly depleted due to precipitation of barite. However, mass balance highlights an additional sink for sulphate, possibly reduction to sulphide. Excess silica present in the produced fluid is ascribed to dissolution of silicate phases in the reservoir. Concentrations demonstrate that the produced water is always close to quartz saturation at reservoir temperature, irrespective of the proportion of seawater produced. Analysis of produced water chemistry provides insights into the inner workings of the reservoir system during a waterflood. Study of individual dissolved species relative to linear mixing lines between injected and formation water allows measurements of the nature and amounts of dissolution and precipitation reactions affecting scaling ions within the reservoir. This allows for greater understanding of the controls on water composition and of the nature of water mixing in the reservoir, leading to improved prediction and planning of scale occurrence, prevention and remediation. Introduction Seawater, either untreated or chemically modified, is commonly used for waterflooding offshore oil reservoirs, for pressure support and improved oil recovery. Injecting a fluid into a reservoir with which it is in neither thermal nor chemical equilibrium will have a number of effects. The injected fluid will react both with the water already in the pore spaces of the rock (formation water) and with the minerals in the rock itself. Changes in pressure and temperature will change the thermodynamic stability of the dissolved fluid constituents. As noted by McCartney and others1, the most important effects of seawater injection can be recognised by studying the changing composition of produced water through time. Situated in the North Sea, Field X has undergone continued monitoring of produced water compositions from all its wells, culminating in a high-quality time-series database. Initial interpretation of the data was for the identification of scaling, but through continued study of all the data we have highlighted evidence of a number of other chemical reactions occurring in the system. Overall, produced water analyses indicate that mixing between injected and formation water has occurred to different extents throughout the reservoir. In addition, the data show that produced water is significantly depleted in barium, sulphate and magnesium and enriched in calcium and silicon relative to a simple mixture of injected and formation water. This paper aims to summarise the most important points raised in the study of the fluid data and in particular highlights the many potential uses and applications of produced water analyses.
- Geology > Mineral > Sulfate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Geology > Mineral > Silicate > Phyllosilicate (0.49)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- North America > United States > Texas > Permian Basin > Central Basin > Means Field > Wolfcamp Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/12a > Birch Field (0.99)
- Europe > United Kingdom > Kimmeridge Formation (0.99)
Mechanistic Understanding Of Rock/Phosphonate Interaction And Effect Of Metal Ions On Inhibitor Retention
Tomson, Mason B. (Rice University) | Kan, Amy T. (Rice University) | Fu, Gongmin | Shen, Dong (Rice University) | Nasr-El-Din, Hisham A. (Saudi Aramco) | Saiari, H.A. (Saudi Aramco) | Al Thubaiti, Musaed M. (Saudi Aramco)
Abstract This paper discusses the effects of Ca2+, Mg2+, and Fe2+ on inhibitor retention and release. Better understanding of phosphonate reactions during inhibitor squeeze treatments has direct implication on how to design and improve scale inhibitor squeeze treatments for optimum scale control. Putting various amounts of metal ions in the inhibitor pill adds another degree of freedom in squeeze design, especially in controlling return concentrations and squeeze life. Phosphonate reactions during squeeze treatments involve a series of self-regulating reactions with calcite and other minerals. However, excess calcite does not improve the retention of phosphonate due to the surface poisoning effect of Ca2+. The squeeze can be designed so that maximum squeeze life is achieved by forming a low solubility phase in the formation. Addition of Ca2+, Mg2+, and Fe2+ in the pill solution at 0.1 to 1 molar ratios significantly improves the retention of phosphonate. Alternatively, these metal ions can be dissolved from the formation while an acidic inhibitor pill is in contact with the formation minerals. Both BHPMP and DTPMP returns were significantly extended by the addition of metal ions, e.g. Ca2+ and Fe2+. The addition of Mg2+ may increase the long-term return concentration, which is important for some wells where a higher inhibitor return concentration is needed. The laboratory squeeze simulations were compared to two field return data obtained from squeeze treatments performed on two wells located in a sandstone reservoir in Saudi Arabia. The sandstone formation contains significant amounts of iron-bearing minerals. Introduction Mineral scale formation is a persistent problem in oil and gas production, especially in older reservoirs with increased water production and drawdown. Inhibitor squeezes are commonly used to deposit the scale inhibitors into the formation. During an inhibitor squeeze treatment, a volume of the inhibitor solution is pumped into the formation and followed by injecting another volume of brine or diesel to place the inhibitor further away from the well bore and allowing it to react with the existing rock. During production following a squeeze treatment, the inhibitor is slowly desorbed or dissolved into the formation water. Earlier efforts have focused on describing what happens and when to re-squeeze.[1,2] More recent papers have advanced the knowledge of inhibitor reactions under various production conditions.[3–1]2 The primary conclusions from several previous studies of NTMP(aminotri(methylene phosphonic acid))-calcite reaction are[13–16]:The extent of NTMP retention by carbonate-rich formation rock is limited by the amount of calcite that can dissolve prior to inhibitor-induced surface poisoning; Calcite-surface poisoning effect is observed after approximately 20 molecular layers of phosphonate surface coverage that retards further calcite dissolution; The consequence of retarded calcite dissolution is that less basic ion,, is released into solution, leaving the solution more acidic; therefore, more soluble calcium phosphonate solid phases form. The inhibitor return concentration can be altered by changing the inhibitor concentration in the pill. The ability to control the high inhibitor return may be useful in initial water breakthrough where high inhibitor return is desired. Kan et al.[17] also compared the retention of NTMP, DTPMP (diethylenetriamine penta (methylene phosphonic acid)), BHPMP (bis-hexamethylenetriamine penta (methylene phosphonic acid)) and PPCA (phosphinopolycarboxylic acid) with pure calcite, a calcite-rich chalk rock, a calcite and clay-rich formation rock from Guerra ranch, McAllen, TX and a quartz sandstone with very little calcite from Frio formation, Galveston County, TX. Similar inhibitor returns were observed in both calcite-rich and low-calcite rock, suggesting that calcite is the primary solid responsible for phosphonate retention. Clays or other minerals play a secondary role in phosphonate retention. The retention of the polymer-based inhibitors is much lower than phosphonates. The data show that BHPMP provides the highest squeeze life at MIC > 50 mg/L. DTPMP is the preferred inhibitor at MIC between 1 and 50 mg/L and NTMP is the preferred inhibitor at MIC < 0.3 mg/L.
- Europe (1.00)
- North America > United States > Texas > Galveston County (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Geology > Mineral > Silicate (0.88)
Abstract Reliance on low sulphate seawater as sole protection against sulphate scale may be discomforting to some operators when such expensive subsea wells are at stake. Normal methods such as bullheading squeeze chemicals are nearly impossible to implement due to the long and sometimes multiple flow lines connecting injection wells. Subsea intervention to place squeeze inhibitors is prohibitively expensive due to the requirement of utilizing a service boat over the well for many days.[1] Calculations of scaling index from formation and injected seawater mixtures are routinely based upon the thermodynamics of the mixed brines. Although some mixing does occur in the interwell distance, the most vigorous mixing occurs in the vicinity of the production wellbore where water from multiple layers and streamlines impinge. These near wellbore mixtures have short residence times before being produced therefore reaction kinetics must be considered, and it is not clear how low the sulphate concentration in injected water needs to be to delay scaling downhole. This work offers a fresh look at this scaling problem by examining the kinetics of the mixed brines. Using data from existing field projects that currently inject desulphated seawater, the induction times required for non-scaling fluid transit up production wellbores are chosen, and the sulphate concentrations necessary to provide these induction times are computed from a software program.[2] The software algorithms are based on a broad, robust database of barite kinetics that span large variations in sulphate and barium concentrations, temperatures and salinities.[3] This protocol is compared to scaling index results computed from a thermodynamic approach at both bottomhole and wellhead conditions. A tandem role in which inhibitors can be utilized in conjunction with low sulphate seawater is described. Introduction With the development of deep offshore production beginning around the end of the last century the complexion of sulphate scaling problems took on new dimensions. These projects, in waters of depths of several thousand feet, are often developed around floating production and storage offloading (FPSO) vessels. Wells are sometimes tens of kilometers from the vessel itself and are connected from subsea wellheads to the FPSOs by long flowlines. In many cases several production wells are connected by manifolds and produced fluids flow to the FPSOs in a single flowline. These so-called ‘daisy chains’ are difficult to utilize when treating a single well from the FPSO. In addition, the producing wells themselves are often completed as laterals of significant length with no downhole zone isolation capabilities. There are many projects like this now in the world but some examples are: Girassol, Plutonio, Roncador, Kizomba B, and most of the P-numbered Brazilian projects.[4,5,6,7] In such cases, bullheading inhibitor fluids downhole from FPSOs has become very difficult and expensive.[1] Intervention from a workboat floating over the subsea wellhead can be done, but again is very expensive. As a result, the industry has begun to rely solely upon sulphate removal from the injected seawater as a means of prevention of sulphate scale formation downhole in the producing wells. When it was initially conceived sulphate removal technology (SRT) was not intended to provide total protection against scale formation. In the early 1980s, South Brae in the Brae field complex in the North Sea was under development by Marathon Oil Company and confronted with severe barite scaling problems. The barium concentrations were as high as 2000 mg/l in some reservoir layers and the temperature was 250+ deg F. A two-pronged solution: 1) reduce the sulphate concentration in the injected seawater, and 2) develop a new inhibitor capable of withstanding higher temperature, minimizing reservoir damage and providing effectiveness at lower sulphate concentrations provided by membrane treatment was used. Modification of existing nanofiltration membranes to be sulphate specific in their rejection characteristics provided the capability to lower sulphate concentrations to the 100 mg/l concentration level.8,9 Development of a new polyvinylsulfonate inhibitor provided endurance at high temperatures and was effective at high barium concentrations once sulphate concentrations were lowered into a manageable range.10 At S. Brae an additional problem was encountered early-on before SRT was developed; raw seawater had to be injected to keep the reservoir above the bubble-point in some regions/layers. The tandem approach of SRT and inhibitor worked well when desulphated water was placed ahead of the advancing untreated seawater but due to interpretation of the complex geology this was not possible in all cases.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.48)
- South America > Brazil > Campos Basin (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7b > South Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7a > South Brae Field > Brae Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (1.00)
Abstract Chang 3 reservoir in Hua 152 block is located in the Ordos basin, China. The average permeability and porosity is 3.17mD and 14.9%. There exists serious scaling at the oil layer near to bottom hole because of high salinity formation water and incompatible injection water. The scaling process and mechanisms in the layers has been researched by means of a visual real-sand micro-model. The results have shown that:The permeability of the oil layer will reduce by 40% when formation water contacts with injection water twice times at the same place; It is very easy for scaling molecules to crystallize from water phase and scale particles are very small because the pores and throats of the formation rock contain a lot of fine clay and impurity; The scale accumulates in pores and looks like "chicken roost"; The scale inhibitors can reduce scaling, but the higher concentration of scale inhibitors is needed. Scaling in low permeability reservoirs may significantly reduce rock permeability thus affecting the production of oil well. The visual real- sand micro-model is a good method to use in research of scaling mechanisms because of its visualization, using actual rock and ease of construction. Introduction If injection water with formation water is incompatible in reservoirs, scaling deposition will be produced and cause formation damage[1–3], and maybe even make permeability reduce by over 90%. There are several factors that influence the degree of scaling damage, that is:Reservoir properties like permeability, porosity, pore structure, heterogeneity, rock composition, reservoir temperature and etc. Ion composition and concentration of injection water and formation water. The scale distribution, scale composition, scale morphology and scale quantity. Therefore, it is important and essential for realizing scaling process and decreasing scaling trend to study[1–5] scaling mechanism in different reservoirs. Many researchers have done a lot of work about scaling damage mechanisms; the main damage mechanisms are as follows:Scale crystals are formed from heterogeneous-phase nucleation in porous media and grown on the surface of pore and throat. Pore and throat are reduced because of scale crystal growing larger. Scale crystals plug pore and throat because of migration in porous media. Core and sandpack experiments are the main methods of studying scaling mechanisms. But it is difficult to observe the scaling formation and distribution directly by means of these methods. So the results and discussions in this paper relate to the scaling and damage mechanisms of Chang 3 low permeability reservoirs in Hua 152 block by using the real sand micro-model, which is made using reservoir rock cores. Scale distribution can be observed under the microscope directly and the degree of scaling damage can also be obtained using the method. Reservoir characteristics Chang 3 formation is located in the Ordos basin of China and belongs to low permeability lithologic oil reservoirs. The average permeability and porosity is 3.17mD and 14.9% respectively. The formation rock is mostly made of arkose aleurolite. The composition of the formation rock is shown in table 1. The maximum throat diameter, which contributes to rock permeability, is 1.24 to 3.2µm based on intrusive mercury method.
- Asia > China > Shaanxi Province (0.69)
- Asia > China > Shanxi Province (0.55)
- Asia > China > Gansu Province (0.55)
- North America > United States > California > Sacramento Basin > 3 Formation (0.99)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- (3 more...)
Abstract Horizontal, extended-reach, and multi-lateral wells are drilled to maximize production from oil and gas reservoirs. Treating these wells with scale inhibitor is a real challenge. This is mainly due to reservoir heterogeneity and chemical placement. Several horizontal wells were drilled in a sandstone oil reservoir. These wells were completed with 1,000 to 1,500 ft of pre-packed screens and produced wet crude with water-cut ranging from 5 to 30 vol%. The total dissolved solids of the produced water was nearly 8,000 mg/L. The bottom hole temperature is 152°F. The porosity varied from 5 to 30 vol%, whereas the permeability varied from 1 to 3,000 md. Calcium carbonate scale was detected downhole due to temperature and pressure changes that occur at the intake of the electrical submersible pumps. The scale was removed by an acid treatment. However, there was a need to develop a chemical treatment to mitigate scale in these horizontal wells. An emulsified scale inhibitor squeeze treatment was developed and applied in several horizontal wells in the sandstone reservoir. The emulsified inhibitor has high viscosity which decreases with the shear rate (shear thinning behavior). These rheological properties enhanced placement of the inhibitor across the target zone. Coiled tubing was also used to place the emulsified inhibitor, which also enhanced the placement of the inhibitor across the target zone. The treatments were successfully applied and no operational problems were encountered. Oil production and water-cut did not change as a result of the scale inhibitor (phosphonate-type) squeeze treatment. This paper will discuss the design of the emulsified scale inhibitor squeeze treatment, field application, and analysis of produced fluids. Introduction Scale mitigation and prevention is one of the challenges that oil-field industry has faced over the years. Inorganic scales form due to changes in temperature and pressure (calcium carbonate) or due to mixing of in-compatible waters (e.g., barium and strontium sulfates). There are several techniques to mitigate scale formation. The most important ones are: forced precipitation of the inhibitor in the pore spaces;[1–9] and adsorption of the inhibitor on the rock and clay surfaces.[2,5,10] It is important to note that the scale inhibitor is injected as an aqueous phase in both cases. One major disadvantage with water-based inhibitor treatments is the injection of large volumes of water, which can cause water-blockage, especially in tight formations.[11] To overcome this problem, several methods were introduced. The first method relies on the injection of an oil-soluble inhibitor.[12] However, this method is limited to dry or low-water cut wells. The second method includes placement of the inhibitor in an encapsulated form in the rat hole.[13–15] This method is limited to vertical wells with reasonably long rat holes. The third method includes injection of the inhibitor in a micro-emulsion form.[16–18] Still a fourth method that was developed by Nasr-El-Din et al.[19,22] included preparing the scale inhibitor in a macro-emulsion form. The emulsion consists of 30 vol% diesel and 70 vol% aqueous phase, which contained the scale inhibitor. The emulsified scale inhibitor treatment was applied successfully in more than 35 vertical wells.[19,22] Unlike vertical wells, horizontal wells have longer target zones and can cross heterogeneous zones with large permeability contrast. Placement of scale inhibitor in these cases is critical. Injection of a scale inhibitor in an aqueous phase means that the inhibitor will flow into high permeability zones only. One way to overcome this problem is to increase the viscosity of the inhibitor solutions using polymers.[23,24] Another way, is to use the inhibitor in an emulsified form, the case of interest in the present study. The emulsified scale inhibitor that was developed by Nasr-El-Din et al.[19] was used to treat horizontal wells. This type of inhibitor was selected because it was employed in vertical wells without encountering any operational problems. The life time of the treatment for vertical wells was nearly three years. The viscosity of the inhibitor was relatively high, which is needed for better placement in horizontal wells with heterogeneous formations. The objectives of the present paper are to:design a scale inhibitor squeeze treatment for horizontal wells, apply the treatment in the field, and assess the performance of this treatment based on field results.
- Europe > United Kingdom (0.96)
- Asia > Middle East > Saudi Arabia (0.70)
- North America > United States > Texas (0.46)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.77)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Norway > North Sea > North Sea Basin (0.99)
- Europe > Netherlands > North Sea > North Sea Basin (0.99)
- (8 more...)