bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a New Polymer Inhibitor Chemistry for Downhole Squeeze Applications
Authors: Montgomerie Harry , Chen Ping , Hagen Thomas , Vikane Olav , Matheson Rozenn , Leirvik Vibeke , Frøytlog Cato , Sæten Jens Olav 
Published: May 2008

Abstract
Inhibitor squeeze treatments have been regularly carried out to prevent both sulphate and carbonate scale depositions in a North Sea field since 1990s. Some of the wells, in which the fluid is producing from the "clean" sandstone formation, had experienced a relatively short squeeze life when a conventional phosphonate scale inhibitor was squeezed. Through a research program, a polymer inhibitor was developed and a number of laboratory static and dynamic tests were conducted to evaluate the performances of the newly synthesized polymer inhibitor. Several field trials were also carried out with a satisfactory result.
This paper outlines the idea of how the new inhibitor chemistry was developed and how a special monomer was introduced to make the co-polymer inhibitor. The monomer was introduced to enhance the inhibitor adsorption property since it carries a special function group to have a good affinity to the reservoir rock. This special function group plays a key role for the newly developed scale inhibitor to offer a good squeeze life. The amount of the monomer had to be optimized in order to achieve a good balance to make the inhibitor to be desorbed/released from the reservoir rock. In addition, the environmental property of the polymer was also improved due to the introduction of the special monomer. A number of beaker and dynamic loop tests were carried out and the inhibitor showed an excellent efficiency in both sulphate and carbonate scale inhibition under the test conditions.
The paper also presents the detailed laboratory and field data. In addition, the treatment design strategy and deployment method of the scale inhibitor are discussed.
Experimental Study and Field Implementation of Scale Inhibitor Squeeze Treatments in ShengLi Oilfield of China
Authors: Zuo Jingluan , Ren Shaoran , Fan Zexia , Yan Fangping , Xu Liang , Hu Kaiming , Wang Xiqiang , Chen Hanwei 
Published: May 2008

Abstract
F41 Block is located in the southwest of ShengLi Oilfield, DongYing, East China. The field has been operated for over 20 years. Water flood started in late 1990s using water from nearby aquifers and produced water. The reservoir is characterized with multi-thin oil layers of low permeability and high clay content, and saturated with medium light oil at temperatures of 110-120 °C. Carbonate scales were discovered since 2002, which formed in perforation holes, casing surface, tubing and surface facilities, having a great impact on well production. Frequent downhole scale clean-ups using acids and solvents have been carried in the past in an interval of around 3-6 months.
To control the scale problem and improve oil well production, scale inhibitor squeeze treatment has been tested to replace acidizing since 2006. A combined acidizing and inhibitor squeeze treatment has also been tried in the field for oil wells treated by the squeeze technique in the first time, in order to improve the treatment efficiency and reduce workover time. Experimental study has been conducted for selection of scale inhibitors in terms of chemical compatibility, efficiency of scale control, and adsorption characteristics of the scale inhibitors designed for squeeze treatment. The squeeze treatments have been performed in 6 oil wells, and good performances on inhibiting scale, increasing oil production, and improving pump efficiency have been observed. The squeeze life is expected to be more than two years. This paper reports the results of the experimental study and field operations. This was the first time of applying inhibitor squeeze technique to replace the traditional acidizing to deal with carbonate scales in ShengLi Oilfield. Its success and wide application will have a big implication on safe field operation and local environment protection (by reducing waste acid disposal) in the region.
Thermodynamic Modelling of Naphthenate Formation and Related pH Change Experiments
Authors: Mohammed Murtala A. , Sorbie K. S. , Shepherd A. G. 
Published: May 2008

Abstract
The prediction and prevention of both sodium and calcium naphthenate "scales" is an important issue in oil production. A broad description of how these scales form has been available for some time although most experimental findings are still of a qualitative nature. In this paper, we present an equilibrium thermodynamic model for predicting naphthenate partitioning and precipitation in an oil/brine immiscible system from some chosen initial conditions (i.e. naphthenate initial concentration in oil, brine pH and [Ca2+] etc). This model has, with some assumptions, been applied to both model and real naphthenate system.
This model describes two types of naphthenate experiment, viz. (i) full naphthenate precipitation, and (ii) simpler "pH change" experiments where no precipitation occurs. In order to predict naphthenate precipitation, the theory suggest that we need to know (a) the partition coefficient of the naphthenic acid, HA, between the oil and the water phases, Kow; (b) the pKa of the naphthenic acid in water; and (c) the solubility product, KCaA2 (or other similar solubility parameter), of the naphthenate deposit. In the simpler pH change experiments, we only require the first two of these parameters, i.e. Kow and pKa. Using the naphthenate model without precipitation, we studied the effect of varying parameters on the degree of pH change predicted at equilibrium in the oil/naphthenic acid/brine system. We also applied the model to examine the sensitivities of the various parameters on the final pH. The comparison between the model predictions and experiment at a higher brine pH value is overall satisfactory.
Oil Field Data/Return Analysis: A Comparison of Scale Inhibitor Return Concentrations Obtained With a Novel Analytical Method and Current Commercial Techniques
Authors: Thompson Alan , Gangstad Audun , Kotlar Hans Kristian 
Published: May 2008

Abstract
A new method for detection of polymer-based scale inhibitors is presented. This method is based on traditional chromatographic technique (HPLC) combined with a novel detection system.
Real samples were obtained from several commercial squeeze programs performed on various North Sea fields. The scale inhibitor concentrations were obtained using the novel analytical method and compared to current commercial techniques. The obtained data demonstrate that the novel HPLC method can generate reliable data where the current commercial techniques fail.
This new method will have implications on the overall interpretation of the scale inhibitor return profiles, including: i)what will be the correct parameters to use for the determination of squeeze lifetime?ii)what will be the actual protected water volume above calculated MIC?iii)at what concentration should a re-squeeze be performed?iv)what are the overall economic implications of the treatment?
The HPLC technique is, however, still under development. Further work planned for the technique includes obtaining better resolution for similarly sized polymers thus opening the door to the individual analysis of scale inhibiting polymers from co-mingled well fluids and an improvement in the sample preparation techniques.
Inhibitor Selection for Iron Scale Control in MEG Regeneration Process
Authors: Guan Hua , Cole George , Clark Paul 
Published: May 2008

Abstract
The formation of iron-containing scale due to high dissolved iron content and increased pH (≥8.5) has been observed in a monoethylene glycol (MEG) regeneration system. The control of iron scale deposition under these harsh conditions causes recurring problems in the re-boilers, requires frequent filter change-outs and remains a challenge to the field. To investigate this problem, a modified corrosion testing apparatus was employed to replicate the iron scale formation and to evaluate the performance of selected chemicals under realistic field conditions (specifically: low pH caused by carbon dioxide dissolution; higher pH due to carbon dioxide boiling off from the re-boiler and alkali addition for corrosion control). Both pH and iron levels (including dissolved iron, ferrous iron Fe2+ and total iron) were closely monitored; additionally digital photos were taken at various stages.
There are several challenges associated with the inhibition of iron scale in systems with high iron level (≥150 ppm), high MEG content (≥60%) and high pH (≥8.5). These factors contribute to incompatibility and poor inhibition by conventional inhibitor species. A number of scale-inhibitor products, scale dissolvers and their blends were tested under aerobic or anaerobic conditions. One product was identified to have greatly reduced the rate of scale formation and at higher dosage, indefinitely delayed scale formation. This product also showed the capability to re-dissolve deposits already present in the system.
Evaluation of iron scale inhibitor is a challenge due to the debatable iron-poisoning effect and the lack of standard laboratory methodology. In this paper, the propensity of various iron deposits (e.g., iron carbonate, and insoluble iron/inhibitor complex) is discussed. Moreover, the formation of soluble iron/inhibitor complex is quantified; this could have important implications for the remediation of iron-containing scale.
Enhanced Inhibitor Treatments With the Addition of Transition Metal Ions
Authors: Kan Amy T. , Fu Gongmin , Shen Dong , Al-Saiari Hamad , Tomson Mason B. 
Published: May 2008

Abstract
This paper discusses the research on scale inhibition and squeeze performance in the presence of a transition metal ion, such as Zn2+. Some scale inhibitors have poor retention characteristics in conventional squeeze treatment, where less than 50% of the inhibitors are retained in the formation. In this study, it was demonstrated that over 90% of the same scale inhibitor was retained when Zn2+ was included in the squeeze formulation. Furthermore, Zn2+ showed significant synergistic effect on barite scale inhibition of certain scale inhibitors. Together with phosphonate, Zn2+ also demonstrated a synergistic effect on corrosion inhibition. Laboratory squeeze and flowback simulation and inhibitor efficiency testing under realistic oilfield condition will be discussed. The solution complexation and precipitation chemistry of common phosphonate and polymeric inhibitors with Zn2+ have also been studied. Stronger solution complexes are observed for common scale inhibitors with Zn2+ than that with alkaline earth metal ions, such as Ca2+, Mg2+, and Ba2+. This stronger solution complex formation with transition metal ions may attribute to the observed enhanced inhibition efficiency. Due to the lower solubility of the transition metal ion-scale inhibitor salts, the transition metal ions added to the inhibitor pill significantly improve the retention of some scale inhibitors during squeeze treatment. In this paper, the projected squeeze life (PSL) is defined. When Zn2+ is used in the inhibitor pill, the projected squeeze life for BHPMP is increased by a factor of 60 without significantly impact the environment and cost. Simulation indicates that the squeeze life may be improved from 110 days to 18 years at the Guerra well if this new squeeze procedure is used.
Control Placement of Scale Inhibitors in the Formation With Stable Ca-DTPMP Nanoparticle Suspension and its Transport Porous Media
Authors: Shen Dong , Zhang Ping , Kan Amy T. , Fu Gongmin , Farrell Jesse , Tomson Mason B 
Published: May 2008

Abstract
Diethylenetriaminepentatakis(methylene phosphonic acid) (DTPMP) is commonly used in oilfield for scale inhibition. In this study, Ca-DTPMP submicron-sized particles were prepared directly by chemical precipitation with the assistance of phosphino-polycarboxylic acid (PPCA). The influences of adsorbed PPCA, KCl concentration and sonication on the transport and deposition kinetics of Ca-DTPMP particle suspensions in calcite and sandstone matrix were investigated. Adsorption of PPCA to Ca-DTPMP particles increases their negative surface charge and decreases particles deposition in a porous media. The mobility of PPCA-coated Ca-DTPMP particles decreases with increasing KCl concentrations. Using sonication treatments the mobility of Ca-DTPMP particles at high KCl concentration in porous media increased significantly. The retention and long term flow back performance of Ca-DTPMP particles were tested in Frio sandstone columns after 18 hours shut-in time to allow deposition. The results show that enhanced retention of Ca-DTPMP particles and slow dissolution of DTPMP are highly advantageous in slowing the phosphonate release from porous media, and ensuring successful inhibitor treatments in oil fields.
Iron (II)-Calcium Carbonate: Precipitation Interaction
Authors: Al-Saiari H. A. , Yean S. , Tomson M. B. , Kan A. T. 
Published: May 2008

Abstract
Little attention has been paid to the reaction of mixed calcium-iron carbonate in solutions in comparison with the reaction of other solids such as calcium carbonate, calcium sulfate and barium sulfate. As a result, little information is presently available about the interaction and precipitation of iron carbonate; and mixed calcium/iron. It is known that iron carbonate precipitation kinetics is sensitive to temperature. At high temperature (65 °C), a sharp drop in iron concentration was observed during the first minutes in a solution devoid of calcium. And the drop was gradual at 55 °C. However, adding calcium to the solution under the same conditions had a great influence in reducing the drop in iron concentration. The apperant increases in the solubility of ferrous iron was proportional to the concentration of calcium present in the solution. In addition, presence of calcium in solution also reduced the effect of temperature on siderite precipitation. On the other hand, the presence of iron did not show significant impact in the solubility of calcium. The cumulative molar ratio of ferrous iron to calcium in the precipitated solid was found to be varied based on the amount of siderite that initially precipitated. The X-ray diffraction analysis showed that the presence of ferrous iron inhibited the growth of calcite but did not prevent the formation of aragonite. The crystal shape of siderite, showed by scanning electron microscope, was completely different from that of calcite and the crystal shape of the solid collected in the co-existence of ferrous iron and calcium varied based on the molar ratio of iron to calcium in the solution.
Scale Squeeze Evaluation Through Improved Sample Preservation, Inhibitor Detection and Minimum Inhibitor Concentration Monitoring
Authors: Ramstad Kari , Rohde Hans Christian , Tydal Trine , Christensen Dorthe 
Published: May 2008

Abstract
In North Sea oil and gas fields, seawater injection is used for reservoir pressure support. Formation water and seawater mixing may lead to sulphate scaling in the near wellbore area, tubing and process systems. Scale inhibitor squeeze treatments are applied to protect the producers and extend the field lifetime. Reducing cost and prolonging the squeeze lifetime is essential. In some StatoilHydro operated fields, squeeze lifetime has been evaluated based on inhibitor return concentration and cumulative water treated. Field experience and laboratory studies have determined the criteria for re-squeezing the wells.
One critical aspect of downhole scale management is the laboratory determined Minimum Inhibitor Concentration (MIC) of the squeeze inhibitor. If the MIC is lower than the concentration of inhibitor required to prevent scale at real conditions the well could scale up. Field examples are given where sulphate scale was observed downhole and in the tubing around the safety valve even if the inhibitor concentration was above the laboratory determined MIC. MIC varies throughout the well lifetime according to variation in brine chemistry/operating conditions and should be re-evaluated frequently.
Polymer squeeze inhibitors are difficult to measure with sufficient accuracy at low concentration. However, adequate preservation of the water samples may improve the detection. The volume of water produced before reaching MIC can be significantly increased with improved inhibitor detection methods.
Laboratory studies have been performed addressing the sensitivity of inhibitor detection as function of ion composition, inhibitor concentration, particles and preservation additive. Parallel samples have been taken offshore. MIC has been determined for a range of formation/seawater mixtures.
The paper describes laboratory analyses, sampling procedures, well monitoring, inhibitor return detection and field/well lifetime MIC determination as methods to determine a long but safe squeeze lifetime.
Radial Core Flood Placement Tests
Authors: Stalker R. , Littlehales I. J. , Graham G. M. , Oluyemi G. F. 
Published: May 2008

AbstractThe effective placement of chemical squeeze treatments in heterogeneous wells and long reach horizontal wells has proved a significant challenge, with various factors including heterogeneity, crossflow and pressure gradients between otherwise non-communicating zones within the well, all contributing to an uneven placement of the scale squeeze treatment into the reservoir. Current methods to circumvent these problems often rely on extremely expensive coiled tubing operations, staged diversion (temporary shut off) treatments or by designing treatments to deliberately overdose some zones in order to gain placement in other (e.g. low permeability) zones. As part of a multi-sponsor Joint Industrial Project at Scaled Solutions Ltd., a series of papers has been released in recent years describing the development of a near wellbore placement model, Place iTTM v. 3.0 designed to model properly the flow behaviour of both Newtonian and non-Newtonian injection fluids in the near wellbore region. In this paper, we describe the extension of previously reported laboratory dual linear core flood placement tests technology to the radial case, in which the flow behaviour of the injected fluids more closely resembles that in the near wellbore region. By extending the laboratory test technology in this way, we are able to examine directly aspects of fluid propagation in a manner which directly correlates to field behaviour. We will present laboratory test results comparing the placement of fluids with different properties and show how the results from these tests concur with previous findings and calculations from dual linear placement core flood tests, and we will further expand on the importance of non-conventional fluids for achieving improved chemical placement in complex wells.
Evaluation of the Performance of Different Scale Inhibitors to Sulfate Removal Unit
Authors: Santos T. N. , Gorceix Fundação , Bezerra M. C. M. , Rosa K. R. S. A. , Rocha A. A. 
Published: May 2008

Abstract
The Sulfate Removal Unit (SRU), a nanofiltration system, reduces seawater's Sulfate ions from approximately 2,800 mg/L for 100 mg/L or less. This technology minimizes the formation of Sulfate scales in the oil production. This process uses pressure as a driving force and it uses membranes with nanometric pores that are composed of polymeric material. Decrease in permeability is frequently observed in this nanofiltration process due to the deposition in the surface of the membrane (biofouling and inorganic deposits). The objective of this study is the evaluation of scale inhibitors for Calcium Sulfate that can be formed in the membrane as a consequence of the concentration of the seawater in the SRU. The feed, permeate and concentrate fluids of the SRU were characterized. The chemical composition of the seawater in the polarization region (fluid located in the membrane surface) was estimated considering mass transference between permeate and feed fluids of the SRU, and Fick Law. The chemical composition of the seawater in the polarization region presents higher concentration of Calcium, Magnesium and Sulfate than the one in the concentrate fluid (reject). So the polarized seawater is highly saturated regarding Calcium Sulfate. Thermodynamic model MultiScale was applied to assess the scaling tendency (saturation ratio and precipitate mass) in specific points of the SRU under temperature and pressure conditions. The performance of different chemical classes of scale inhibitors was evaluated. Chemical compatibility of these chemicals with seawater in the polarization region, as well as their inhibition efficiency to Calcium Sulfate precipitation in the conditions of the surface of the membrane were evaluated.
Scale Management in Espadarte Field
Authors: Hernandes R. , Melo V. L. A. , Santos J. A. M. , Rosário F .F. , Bezerra M. C. M. , Rosa K. R .S. A. 
Published: May 2008

AbstractEspadarte is an oilfield located offshore in the Campos Basin, Brazil, in water ranging from 750 to 1,500 m depth. The first development plan took place in the beginning of 2000. This plan consisted of 8 producers and 4 injectors. The first oil was produced in Espadarte FPSO in August 2000. In 2002, the well (#1) had shown the first strong presence of Barium Sulphate deposits inside the tubing. After trying to chemically remove the scale without success, the solution was to change the entire tubing string, followed by a displacement of a scale inhibitor. As a precaution, it was decided to stop the water injection in order to reach better understanding of the problem.The Petrobras Research Center gave the necessary support and few months later a scale treatment was designed. With this inhibitor treatment formulation, the operational procedure adopted consisted to inject the inhibitor in a remote way, using stimulation vessels, in order to by-pass the high costs associated with the use of a dedicated rig, since all the wells in Espadarte have wet completion.A detailed plan was prepared in order to cover all the aspects involved in an operation like this, collecting samples of water produced before and after the injection of the inhibitor. Due to the availability of stimulation vessels, the first campaign took place only in 2005 and permitted the return of the water injection in the field.This paper presents the methodologies adopted to prevent, and in some cases to remove, the BaSO4/SrSO4 scale in Espadarte wells.
A Semi-Analytical Model for the Simulation of Horizontal and Slanted Wells
Authors: Barreto W. S. , Amado L.C. N. , Priimenko V. I. 
Published: May 2008

Abstract
This paper presents a semi-analytical solution for the pressure drawdown of horizontal or deviated wells in an infinite reservoir considering the well as a source of infinite conductivity. The solution is obtained using the concept of Green’s functions applied to solve the diffuse equation in radial coordinates for a point in an infinite domain kept at a constant pressure. The solution is employed to generate dimensionless functions in order to investigate the behavior of horizontal or slanted wells. Others analytical solutions available in the Literature are used for validation and comparison of results. Calculation procedures are illustrated in the Appendix A and Β at the end of the paper.