Larsen, Tore (Norwegian U. of Science & Tech) | Lioliou, Maria G. (Institute of Chemical Engineering and High Temperature Processes-FORTH, ICE-FORTH) | Josang, Leif Olav (Norwegian U. of Science & Tech) | Ostvold, Terje (Norwegian U. of Science & Tech)
A new method to prevent sand permeation from unconsolidated or poorly consolidated reservoir formations has been developed. The Quasi Natural Consolidation (QNC)-method involves a controlled in situ precipitation of calcium carbonate scale on sand grains. Experiments show that calcium carbonate forms bridges between sand grains and strengthens the unconsolidated sand pack. The QNC-solution contains Ca2+, urea and urease. When this single-phase solution is injected into the sand pack, calcium carbonate precipitates at a rate which is dependent on the urease concentration and temperature. A series of batch experiments have been carried out in order to establish the optimum solution chemistry/composition for sand consolidation. Consolidation experiments have shown that this method is applicable in the temperature range from 25 °C to at least 65 °C. An untreated sand pack collapsed at a water flow velocity of < 0.01 cm/s (Q/Atot). However, after two QNC-injections at either 25, 50 or 60 °C the sand packs could withstand a water flow velocity >0.38 cm/s without producing sand. The permeability dropped about 25% from the initial ~10 Darcy. Uniaxial strength tests showed that up to 10.56 MPa could be obtained after four injections. Consolidation was obtained also with presence of oil in the sand pack, although with a somewhat reduced efficacy of the treatment. Permeability measurements indicate that the relative water permeability is reduced more than the relative oil permeability after treatment.
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)
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.
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 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.  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]
This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract 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. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Abstract Oseberg Sør field, operated by Hydro Oil & Energy, is situated 130km west of the Norwegian coast on the eastern flank of the Viking Graben structure. It comprises a sequence of fault bounded structural units of varying geological complexity. Within these units the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in permeability and formation water composition.
The formation of calcium carbonate mineral scale is a persistent and expensive problem in oil and gas production. Scaling of metallic or insulating walls in contact with hard water may cause unscheduled equipment shutdown and loss of production. The aim of this paper is to further the understanding of scale formation and inhibition by in-situ probing of crystal growth by synchrotron radiation Wide Angle X-Ray Scattering (WAXS) in the absence and presence of diethylenetriaminepenta (methylenephosphonic acid) (DETPMP) scale inhibitor at elevated temperature and high pressure. This novel technique enables in-situ study of mineral scale formation and inhibition and as such, information on the nucleation and growth processes is accessible. This technique studies bulk precipitation and surface deposition in the same system and has great benefit to understand an industrial scaling system. It offers an exciting prospect for the study of scaling.
It has been shown that the nucleation and growth of various calcareous polymorphs and their individual crystal planes can be followed in real-time and from this the following conclusions are reached.
The process of scale deposited on the surface can be divided into an unstable phase and a stable phase. The initial phase of crystallization of calcium carbonate is characterized by instability with individual planes from various vaterite and aragonite polymorphs emerging and subsequently disappearing under the hydrodynamic conditions. After the initial unstable phase, various calcium carbonate crystal planes adhere on the surface and then grow on the surface.
DETPMP has a profound effect on the induction time of the surface deposit. It inhibits scale crystal adhesion onto the surface, although the bulk precipitate is observed in the scaling system. It displays different inhibition mechanisms for bulk precipitation and surface deposition inhibition.
DETPMP inhibits surface deposition. It suppresses calcite formation and results in the least stable vaterite crystal formation.
This paper will discuss how surface scale evolves in the absence and presence of the inhibitor - exploring the power of the synchrotron in-situ methodology.
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.
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.
Previous work has derived an analytical model for simultaneous flow of incompatible waters in porous media with sulphate salt precipitation, determined typical values of kinetics reaction coefficient from corefloods and what the impact would be on productivity impairment during sulphate scaling.
This paper extends the previous work, by modelling the injectivity impairment during simultaneous injection of incompatible waters, i.e. cation-rich produced water (PWRI) and seawater with sulphate anions. An analytical model with explicit expressions for deposited concentration and injectivity decline was developed.
The location of scale deposition and the resulting injectivity impairment are calculated for a range of sensitivities, including reaction kinetics (ranging from minimum to maximum values as obtained from coreflood and field data), fraction of produced water in the injected mixture and barium concentration in produced/re-injected water.
The theoretical parameter of the size of formation-damaged zone was introduced. It was found out that almost all deposition takes place in 2-4 well radii neighbourhood.
Calculations show that simultaneous injection of seawater with produced water containing even decimal fractions of ppm of barium would results in significant injectivity decline.
Methanol is a common industrial solvent and is added to water to enhance hydrocarbon solubility and to prevent solid hydrate from forming, as well as other applications. One of the side effects of methanol addition to water is it greatly reduces the solubility of ionic solids, particularly divalent solids. The effect of methanol on ionic solubility has been reported only for a few isolated conditions. The effect of hydrate inhibitors on oilfield scale formation has been studied. A semi-empirical approach is proposed to correlate the effect of hydrate inhibitors on scale formation and inhibition from experimental solubility measurements of halite, barite, gypsum, calcite and carbonate equilibrium chemistry. The ion-cosolvent activity coefficients can be used directly in any solution speciation code to evaluate the effect of cosolvent on mineral scale formation. The validity of the equation has been tested between 4-200ºC and 1-6 M ionic strength. Barite solubility is significantly reduced, by as much as 20 fold, with 50% (v/v) methanol. Other mineral solubilities are also reduced significantly. Ethylene glycol has much less impact on mineral solubility than methanol. Good agreements between the model prediction versus both experimental and literature results are observed.
Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE International Oilfield Scale Symposium held in Aberdeen, United Kingdom, 30 May-1 June 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract 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 an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.
Shepherd, A.G. (Heriot-Watt University) | Thomson, G.B. (Heriot-Watt University) | Westacott, R. (Heriot-Watt University) | Sorbie, K.S. (Heriot-Watt University) | Turner, M. (Oil Plus Ltd.) | Smith, P.C. (Oil Plus Ltd.)
Organic field deposits from distinct geographical regions were analysed using a wide range of analytical techniques, viz. for cation composition (EDAX), diffraction patterns (XRD), thermal profiling (DSC/TGA), naphthenic acid distribution using electrospray mass spectrometry (ESMS), nuclear magnetic resonance 1H NMR and solid state 13C NMR. Clear distinctions for end member soap types were observed with regard to the type and amount of cations, the naphthenic acid content, as well as their thermal behaviour. Specific soap samples were analysed along with their parent soap forming crude oils collected from the same field over a period of one year. The nature of two of these soap samples were found to be related to the particular chemical treatment on site. There were clearly observable differences in the final location within the surface facility, as well as the final composition (calcium content, acid distribution, presence of other chemical families) of these samples. These were suggested to be related also to crude oil chemistry changes and mitigation (chemical) strategies used. The implications of these new findings on the basic mechanisms of soap formation are discussed.
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.