Waterflooding with seawater is the most common approach to supporting reservoir pressure and stimulating oil production in offshore installations. However, producing wells can be significantly damaged when seawater breakthrough occurs, as BaSO 4 scale can deposit in the near wellbore area; especially for wells with formation waters containing a high concentration of barium ions. Different ion monitoring and analysis methods are traditionally used to calculate the percentage of seawater breakthrough, with varying levels of accuracy and reliability. This presents a significant challenge, as accurate determination of seawater breakthrough, especially at its onset, is critical for scale management and selection of appropriate mitigation strategies. This paper discusses the development of a simple methodology for seawater breakthrough determination in a North Sea field, using reactive ions. Unlike other approaches, the method calculates the percentage of seawater breakthrough through the balancing of the seawater breakthrough as determined from individual reactive ions; it also allows the determination of BaSO 4 mass deposition downhole, corresponding BaSO 4 mass stripped in the deep reservoir and amount deposited in the near wellbore. The relationship between oil production rate and percentage of actual seawater breakthrough has been correlated based on matching well historical data. The different stages of formation damage as a function of increasing seawater breakthrough are also presented. Last, the difference between the contribution of BaSO 4 stripped in deep reservoir and deposited in the near wellbore on and its impact on formation damage is discussed. This paper presents a comprehensive study of monitoring and calculating seawater breakthrough using a robust and accurate methodology. Seawater breakthrough and the relationship between downhole scale deposition and formation damage have been correlated using real field data. Combined with scale predictions, it is proposed that this approach can enhance scale management strategies and thus optimise oil production. The method is applicable to any oilfield using seawater flooding, rendering it a significant tool in optimising oil production and minimising well downtime.

Silicate scaling during high pH Alkaline Surfactant Polymer (ASP) flooding is known to adversely affect oil production. The silicate scale occurs as a result of the dissolution of silicates under high pH conditions and where the fluids subsequently flow into a region of lower pH where they then precipitate. The precipitation of magnesium silicate strongly depends on solution pH and temperature and is affected by the kinetics of the silicate scaling reaction. In this paper, the effect of pH on the stoichiometry and morphology of silicate scale is studied. A range of spectroscopic techniques, including Environmental Scanning Electron Microscope/ Energy Dispersive X-Ray Spectroscopy (ESEM/EDX), Fourier Transform Infrared (FTIR) and X-Ray Powder Diffraction (XRD) are applied in order to analyse the precipitated silicate scales in the laboratory. These spectroscopic techniques, when used along with reference sample spectra, yield a number of interpretive clues as to the nature of the silicate precipitates which are formed. The further analysis of the solution and precipitate by Inductively Coupled Plasma-Optical Emission Spectroscopy (ICP-OES) and ESEM/EDX also gave complementary information which was consistent with the results obtained from the other spectral methods above. The approach used in this work has enabled us to establish the composition and morphology of the silicate scales formed under different pH condition. There is relationship between the pH conditions and the compounds appearing in the precipitate. Results obtained can be used to help determine the most appropriate type of scale inhibitor for silicate scale mitigation in future.

Halite salt deposition in the near wellbore formation and the wellbore of a gas well can dramatically reduce its productivity within a very short period of time. In order to minimise the salt induced formation damage, it is essential to identify if, where and how much halite will be deposited. The main objective of this work is to develop an easy- to-use tool for downhole salt deposition risk assessment and management. The main mechanism for halite deposition in the near wellbore formation and the wellbore of a gas producer is water evaporation at a reduced pressure. A high deposition risk is expected at a high drawdown and a low produced formation water to gas ratio (FWGR). Halite deposition can also occur at a reduced temperature or pressure due to reduced halite solubility in water. A halite envelope can be used to determine the downhole halite deposition risk, which is a boundary marker for the start of halite deposition at which point halite is saturated in water. Two types of halite envelopes are introduced in this paper. One is for different reservoir pressures at differing FWGRs and but at a fixed temperature. The second is for different temperatures at differing FWGRs at a given reservoir pressure. A number of North Sea gas field halite deposition cases will be presented in this paper. Each case will illustrate how the halite envelope technique can be used to identify high risk wells; their salt free operating conditions or to determine the requirement for water washes, and their associated injected water volumes. It will also demonstrate that for its successful application, reliable measurement of the water and gas production, along with an understanding of the water/gas influx, are both prerequisites in the validation of a halite envelope.

Formation damage and the resultant reduction in hydrocarbon production rates due to clay expansion are long-recognized problems ( Ohen, 1991 ). The clay damage may occur during the drilling, completion and production phases of well operations. Often the remediation of clay damage is inadequate, providing only temporary improvements in hydrocarbon production. The prevention of clay expansion presents a challenge; fit-for-purpose chemistries exist, and are a function of clay identity and operational phase of the well. Two broad subsets of clay damage mechanisms are chemical and mechanical considerations ( Bennion, 2002 ). The focus of this study is to evaluate the minimization of clay hydration by coating clays to prevent chemical or reactive damage. An example of chemically induced formation damage would be clay swelling. On exposure to introduced aqueous fluids, other than interstitial water, sensitive clays will hydrate detrimentally. The end result can be subsequent hydrocarbon flow restrictions due to a decrease in pore space and detrimental formation softening allowing embedment of proppant. Chemical methods of ameliorating clay expandability potential fall into two broad categories: temporary and permanent stabilizers. The temporary clay control additives prevent clay swelling by increasing the ionic strength of treatment fluids, e.g., potassium chloride. Permanent clay stabilizers create a protective sheath around the clay. The formation of a self-assembled monolayer (SAM), where the chemical covalently bonds to the siliceous formation surface, offers a more robust chemical coating on the clay surface. This coating acts as a chemical shield, which prevents subsequent wellbore fluids from interacting with the formation surface. A new chemical treatment has been evaluated and, as discussed in this paper, the laboratory test results indicate the application of a hydrophobic coating offers substantial clay protection in water sensitive environments.

The aim of this paper is to describe a methodology to simulate scale squeeze treatments in acid stimulated carbonate reservoir. Acid stimulation treatments refer to matrix acidizing, which aims to improve productivity in tight carbonate reservoirs. They generally show a high porosity, but very low permeability. Matrix acidizing treatments have been applied successfully in numerous occasions, they consist of the injection of an acid, generally, hydrochloric acid, mainly because of the high reactivity with carbonate formations. When the acid is injected into the formation, a number of wormholes or highly conductive channels are formed, which are the result of two very distinctive, but interconnected processes. On the one hand, there are chemical reactions between the carbonate minerals and the acid and on the other hand, there are the fluid dynamics of the injected acid, i.e. the fluid loss from wormhole to formation and the fluid distribution in possibly highly complex wormhole geometries. There have been numerous studies investigating the geometry of the wormhole growth pattern in radial and linear laboratory experiments, as well as stochastic simulation. They concluded that wormholes grow in a certain pattern in both axial and angular directions. Although the exact wormhole pattern will strongly depend on the permeability anisotropy and heterogeneity, it is reasonable to assume that the dominant wormholes are expected to grow symmetrically, and that the region dominated by each wormhole is approximately 90° around the wellbore. To simulate squeeze treatments in an acid stimulated well with a corresponding wormhole pattern, as described above, a reservoir simulator is used. The reservoir simulator describes the pressure field and consequently the propagation of scale inhibitor (SI) along the wormholes, but also into the matrix. The final step is to determine how deep the SI propagates into the matrix, which was used to determine fully a specialized near wellbore model for scale treatment design.

An existing limitation of chelant-based fluids available for sandstone acidizing with hydrofluoric acid (HF) is the presence of sodium in the concentrate of the aminopolycarboxylate fluid, which is common in all chelating agents soluble below pH 3.5. The presence of sodium complicates stabilization of the fluid during acidizing processes because of the myriad of chemical reactions that can impact the outcome of a treatment. The use of chelating agents has expanded the temperature range as well as the type of clay minerals that can be exposed to an HF fluid; however, limitations still exist. Core flow testing at 360°F and corrosion testing from 265 to 360°F were conducted. Flow tests were performed using outcrops of two types of sandstones and inductively coupled plasma (ICP) analysis was conducted to elucidate the ionic composition of the spent fluid. Results reported stem from core flow testing with glutamic acid diacetic acid (GLDA) containing HF at very high temperatures (360°F). To encompass a broad range of mineral composition, two types of sandstone cores were employed—heterogeneous (Bandera, 65% quartz) and clean (Leopard, 95% quartz). Corrosion inhibition of the GLDA/HF fluid for use with coiled tubing (CT) was achieved up to 320°F, employing varying classes of inhibitors. The GLDA/HF fluid exhibited lessened corrosion tendencies and could be inhibited for at least 6 hours at 360°F for drillpipe (mass loss rates of 0.025 to 0.05 in./ft 2 were obtained). The presence of sodium in GLDA/HF could be managed, leading to effective permeability improvement of the Bandera core, while the Leopard core underwent a decrease in overall permeability; this latter observation was attributed to the formation of metal fluorides. Neither the presence of CaCO 3 in the Bandera substrate or the use of KCl brine substituting for the usual NH 4 Cl led to permeability impairment. The overall results indicated that 1% HF and 0.6 M GLDA with an auxiliary agent could circumvent the expected problems associated with HF acidizing and modification, volume minimization, or elimination of preflushes. The use of the GLDA chelant facilitates, when using CT to deliver fluid to hot zones (which can be susceptible to formation damage if aggressive fluids based on HCl or formic acid are used, or if acetic acid is employed), could be jeopardized because of the difficulties inhibiting the corrosive effects of HF, HCl, formic, or acetic blends.

Complex technical problems, including salt precipitation, can occur during the entire period of the operation and production of the oil from reservoirs in high-pressure/high-temperature (HPHT) condition. Inorganic salts deposition occurs during the mixtures of different waters, which are incompatible with each other. These combinations of waters mostly can be done during waterflooding into the reservoirs to pressure maintenance. For the effective development of oil reservoirs, which are associated with the deposition of inorganic salts in HPHT, the selection of inhibitors is required to prevent scaling accounts for the characteristics of the reservoirs. Effectiveness of the scale inhibitors concentration for specific well conditions is verified by laboratory tests, considering total dissolved salts and hydrochemical conditions of the formation. The amount of calcium carbonate (CaCO 3 )) precipitation in synthetic formation water was investigated in mixing with the injected water in the range of 100-200°C for temperature and 40-70 MPa for pressure. Also, calcium carbonate precipitation was considered in a well at 200°C and 70 MPa in a simulation model with an electrical submersible pump (ESP). The results of the experiments showed that the possibility of calcium carbonate deposition was increased by growing the amount of the formation water and temperature. Increasing the pressure had reverse effect on scale formation. In this investigation, a new inhibitory chemical composition was developed. This scale inhibitor is based on the aqueous solutions of different acids and isopropyl alcohol. The inhibitor was considered for compatibility with formation water and core samples; and it was compatible with them at reservoir condition. The new scale inhibitor had a greater inhibition efficiency and low permeability damage in comparison with the tested inhibitors. The used materials were effective for scale prevention at high-level. The synergistic inhibitory effect has been considered for mixtures of inhibitors.

The most common scale inhibitors (SI) in the oil industry are polymeric and phosphonate species which are widely used to prevent calcium carbonate and barium sulphate scale formation, and these SIs may be applied in the field in downhole “squeeze” treatments. This paper focuses on the underlying mechanisms associated with polymeric precipitation squeeze treatments, where the polymer is precipitated in situ to enhance its retention in the formation and thus extend squeeze lifetime. Three polymeric SIs of similar structure are studied in this work, PPCA, SPPCA and PFC (full names in paper). Inhibition efficiency (IE) results are presented and analysed in terms of the molecular weight distributions (MWD) of the these polymers. IE and MWD results are shown for each for these polymers “as supplied” (the stock solution) and also for the “precipitated” and “supernatant” fractions, as would occur in a precipitation squeeze treatment. For PPCA, this precipitate has been shown to be a calcium complex of the polymer with stoichiometry, PPCA-Ca n (n ≈ 30). It is shown that the precipitated forms of PPCA and SPPCA are more efficient at inhibiting barite than either the stock or the supernatant due to the fact that they preferentially contain the larger molecular weight species, which increased the IE. However, the corresponding inhibition efficiency results for the PFC copolymer are rather different to those for SPPCA and PPCA and this is described in the paper. Further studies of the solubility of the PPCA-Ca n complex in successive samples of fresh brine suggest a “stripping model” for the dissolution/solubility of this complex, in which the lower molecular weight (MW) species are preferentially dissolved into supernatant brine until some equilibrium is reached. This, in turn, results in the original precipitate being enriched in higher MW species which are less soluble than the lower MW species. This model of dissolution is very different from a “solubility product” model as would describe a sparingly soluble mineral salt. This should now be taken into account in the modeling of polymeric SI precipitation squeeze processes, and it also has implications for the laboratory testing of polymeric SIs for application in precipitation squeeze treatments.

An operator in Gulf of Guinea experienced dramatic production impairment due to calcium carbonate scaling. Post completion analysis revealed that the scaling magnitude was dependent upon several influences, primarily the reservoir pressure; access to mobile formation water coupled with its scaling tendency induced carbonate scales deposit. The impact of the completion brine and drilling mud and filtrate as whole losses or secondary filtrate were identified as contributors. The above study and its conclusions were reported concurrent with on-going planning for the next horizontal drill and open-hole gravel-pack completion. The water-base reservoir drilling fluid (RDF), screen running fluid (SF), completion brine, gravel pack carrier fluid, and filter-cake breaker fluid were designed with divalent calcium chloride brine. The required products for these systems were already on location and operations very close to commencing. Redesigning all these systems by replacing the divalent brine with monovalent brine would require additional resources and delay the project. However, a scale inhibitor was recommended to mitigate the initial risk of scale formation when using divalent calcium brine. Concentrations of Scale inhibitors were tested over a range of temperature from 150F to 250F, and ratios between formation water and selected fluids from 25/75 to 75/25. Testing considered adding a scale inhibitor to the RDF as well as the other required systems. This upfront assessment indicated that the selected inhibitor prevented scaling with formation water. As such, the operator approved the use of the scale inhibitor and the well was successfully drilled and completed. Higher initial production than modeled was realized for this well compared to other wells in this field. This paper will present the upfront testing to assess shale inhibitor efficiency, results, and the field application used to reduce the risk of formation damage during the drilling and completion phases.

Core flood testing of phosphonate-based scale inhibitors in reservoir sandstone containing iron minerals revealed potential formation damage caused by unmodified acid phosphonates, which are reactive toward the iron minerals. The mechanism of formation damage was shown to be due to dissolution and re-precipitation of iron phosphonate species, together with fines mobilized (also thought to be due to dissolution effects) which propagated some distance through the core, leading to pore throat blockages. In an example case, complete blockage occurred as the front of the injection chemical reached the outlet of the core due to a combination of silica fines and iron phosphonate chemical. To mitigate the potential issue, different chemical formulations were prepared based on the same phosphonate scale inhibitor, in order to mitigate / minimise the potential for in-situ dissolution of iron bearing minerals within the reservoir formation. This allowed a less aggressive formulation to be prepared by part-neutralisation of the acid phosphonate, so achieving compatibility with the core material. Thus, no formation damage was induced and retention of scale inhibitor by adsorption ensured the potential for long squeeze treatment lifetimes. The modified product has since been applied in the field and results from the laboratory qualification, chemical re-formulation and field treatments are presented in this paper. To date, 27 wells have been squeezed; the part-neutralized chemical targeted at susceptible wells and the acid chemical used elsewhere. Excellent are results in both formation damage and return lifetimes minimising the requirement for coil tubing scale removal treatments in this field.

Scale inhibitor squeeze treatments in unfractured reservoirs can be readily simulated in matrix flow models, designing such treatments for application in fractured reservoirs is less routine. One reason for this is that the flow process and transport mechanisms by which the inhibitors are retained in fractured formations differ considerably from simple matrix flow. In previous papers, we described a diffusion-controlled transport model for scale inhibitors in low permeability fractured reservoirs where little matrix flow is expected. In this paper, the model has been used to simulate squeeze treatments performed on multiple wells in a fractured shale formation and compared to simulations using a matrix flow model. A number of squeeze treatments were performed on wells in a fractured shale formation yielding long treatment lifetimes. The squeeze treatments were designed using a matrix flow model. Calculations indicated the design pumping rate would require an injection pressure significantly more than the fracture pressure for the formation indicating little matrix may possible for this case. The treatments were successful, however, the observed field return did not match the prediction and in some cases longer treatment lifetimes were observed. When a standard matrix flow model was used, the resulting field isotherms were significantly different for each well in the formation. This is taken to indicate that the matrix flow model approach is not accurately mimicking the field data. When the same data was examined using the diffusion based fracture model, a single isotherm was found to be a good match for all of the wells from the formation. In addition, explicitly modelling the varying water production rates in the diffusion model gave good correlation with changing trends in the return concentrations seen in the field return. Furthermore the possibility of improving the treatment lifetime is considered, factors such as the effect of the overflush volume and injection rate are discussed as treatment modifications and the influence may have on formation damage. Accurate prediction of squeeze treatment lifetimes is important for scale management both economically to ensure optimum productivity and practically to schedule treatments appropriately. Until recently this has not been achievable for fractured formations without the use of full field simulators. The paper illustrates that an appropriate near wellbore model can give good agreement with field data and has been used to design better treatments without the need for complex full field simulators.

In waterflooded reservoirs under active scale management produced water samples are routinely collected and analysed, yielding information on the evolving variations in chemical composition. These produced water chemical compositional data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale management programmes designed to minimise damage and enable improved recovery. In this interdisciplinary paper, the analyses of produced water compositional data from the Miller Field are presented and a 1D reactive transport model is developed to study possible geochemical reactions taking place within the reservoir through matching model results with observed produced water data. However, in the 1D reactive transport model, only one flow path was simulated; this does not fully represent the fluid flow and mixing behaviour in the reservoir. Therefore, this paper also presents a fully 3D reservoir simulation study for the Miller Field to evaluate brine flow and mixing processes occurring in the reservoir, using an available history matched streamline reservoir simulation model integrated with produced water chemical data. Conservative natural tracers were added into the modelled injection water, and then the displacement of injection water and the behaviours of the produced water in two given production wells were further studied. In addition, the connectivity between producers and injectors was investigated based on the comparison of production behaviour calculated by the reservoir model with produced water chemical data, and an assessment of the properties of the intervening faults was also performed. Finally, a model of BaSO4 scale precipitation was included in the model, and the simulation results with and without barite precipitation were compared with produced water chemical data (observed barium and sulphate concentrations in the produced brine). In general, the modelled and observed data were found to be in good agreement, but any discrepancies were in fact found to be very informative also. The model assumes scale deposition is possible everywhere in the formation, whereas in reality the near production well zones were generally protected by scale inhibitor squeeze treatments, and thus the discrepancies between modelled and observed data could be used to diagnose the effectiveness of the chemical treatments to prevent formation damage around the production wells.

If only oil and gas wells produced problem free, then flow assurance strategies would become unnecessary. The reality is that problems such as inorganic and organic deposition in the formation, the near wellbore, and the tubulars complicate and add expense to the completion and production processes. In 2005, a technology was introduced by which chemical inhibitors were adsorbed onto a proppant-like substrate and placed in the formation during hydraulic fracture. Since then more than 15,000 wells have been fractured using this solid chemical technology. Upon production of hydrocarbon or water, the requisite inhibitor is released into the fluid stream to inhibit the deposition of contaminants such as scale, paraffin or asphaltenes. However, the strength of the solid substrate limits the amount of material added and the closure pressure applied. This paper discusses a new material that demonstrates no conductivity loss when added at up to 20% by weight to high-strength (bauxite) proppant and up to 16,000 psi closure stress. Furthermore, it maintains chemical adsorptivity similar to the earlier material. For deepwater wells, which are traditionally gravel-packed or frac-packed, the new material can provide multi-year inhibitor life to delay or eliminate future interventions. This represents a significant savings on projected expenditures as well as an ongoing flow assurance program that protects against scale deposition from the formation to the surface.

Sulphate and carbonate scale are the most important types of inorganic scales that can be observed in majority of reservoirs which encounter scaling problem during water injection.[ 8 – 9 – 10 – 11 ] Precipitation of these scales may ends to dramatic permeability reduction during water injection and due to their relative hardness and low solubility there are limited processes for their removal and prevention measures such as ‘squeeze’ inhibitor treatment has to be taken. In this regard, it is important to have a proper understanding of the kinetics of scale formation and trend of scale precipitation with considering the effective parameters on the phenomenon. This paper presents an experimental and theoretical study of calcium sulphate precipitation. A series of experiments were carried out to investigate the effect of different parameters on precipitation of calcium sulphate such as temperature, concentration of brine and flow rate. In addition, three different sets of experiments with the same procedure and different experimental condition were analyzed, compared and contrasted. The functional form of permeability reduction due to effect of different parameters in all experiments persuaded us to device a method to predict precipitation trend. Finally an artificial neural network was developed based on the data that obtained from experimental works. The network can predict permeability with considering effective parameters in each section of precipitation with very good accuracy and because of wide range of entrance data it can be considered as a reliable substitute for time/expense consuming experimental works in different range of time, flow rate, temperature and brine concentration.

Precipitation, deposition and gelling of paraffins are common production chemistry challenges associated with upstream exploration and production. In this paper the different steps used to identify the wax-related issues from project to start-up and steady state are discussed. The development is a field under steam-assisted gravity drainage (SAGD). Critical to the mapping of production chemistry risks are the many specific analytical and modeling procedures employed. During the project stages, the main risks identified were: wax precipitation downhole and potential gelling of the export pipeline. Clear strategies were put in place to manage both these potential problems. During the start-up of the field, a number of wells were suffering from poor inflow performance. A downhole deposit was retrieved and analyzed. This was identified as wax, with an increase in paraffin distribution compared to the parent crude oil. Successful mitigation of wax deposition downhole was achieved for a selective number of wells using a combination of fluid treatment and extended soak time. This suggests wax deposition is occurring in the near wellbore area. Noticeable effects of SAGD drive on the wax properties of individual well samples are observed reflected in increasing pour points (for wells where heat has broken through). No effect yet is observed on the export crude oil. Long-term surveillance for wells and the facility will continue to rely on wax measurements in combination with tubing head temperatures. Mitigation options will be further developed for continuous operational improvement.

Acid treatments in wells drilled in carbonate reservoirs aim to remove the damage, and increase the permeability in the area around the wellbore. Regular HCl used to be the main stimulation fluid; however at high temperatures, HCl causes excessive corrosion, rapid acid spending and face dissolution. For high temperature treatments, the alternatives are limited; including chelating agents, such as GLDA (glutamic acid-N,N-diacetic acid) and HEDTA (N-hydroxyethyl-ethylenediamine-triacetic acid). This paper discusses the evaluation of an innovative technique to formulate a new emulsified chelating agent that can be used for high temperature stimulation treatments. GLDA (pH = 3.8) of 38 wt% initial concentration was selected to formulate the emulsified GLDA (EGLDA). The EGLDA was formulated using a cationic emulsifier, with final GLDA concentration and volume fraction of 20 wt% and 0.7, respectively. The viscosity of the new EGLDA was measured at temperatures up to 300°F using an HPHT rheometer. The reaction of the EGLDA and limestone rock was studied using a rotating disk apparatus at temperature of 230°F. Coreflood experiments were performed using low permeability Indiana limestone core samples and emulsified GLDA at a temperature of 300°F and injection rate of 2.0 cm 3 /min. EGLDA is a non-Newtonian shear-thinning fluid, where the viscosity can be represented by the power-law model. The emulsified GLDA achieved a viscosity of 57.5 cp at 100 s -1 and 75°F. The EGLDA was stable up to 300°F, and the apparent viscosity at 10 s -1 shear was found to be 40 cp. The reaction rates of EGLDA with calcite were in the range of 6.2×10 -8 to 1.2×10 -7 gmole/cm 2 .s, less by 2 orders of magnitude than those of 15 wt% HCl emulsified acid formulated by 1.0 vol% emulsifier and reacted with calcite at a temperature of 230°F. The coreflood experiments performed using EGLDA and Indiana limestone cores, indicated that emulsified GLDA was able to enhance the permeability of the core by a factor of 3.7 times. From the work done, the EGLDA achieved low reaction rates with no face dissolution at high temperature, and this will results in better stimulation treatments, especially in high temperature wells.

Viscoelastic surfactant (VES)-based acid systems have been used successfully in matrix and acid fracturing treatments. However, the existence of Fe (III) as a contaminant in such systems may lead to many problems, due to interactions between VES and Fe (III). Such interactions could reduce the effectiveness of VES-based acid systems and may lead to formation damage. In this paper, reaction mechanisms between VES and Fe (III) were studied. Rheological properties of two surfactants were examined with various concentrations of Fe (III). A scanning electron microscope (SEM) was used to identify precipitates from reaction products. Inductively coupled plasma (ICP) was applied to measure iron concentration, and the two-phase titration method was used to determine VES concentration in all phases of the sample. The effect of several chelating agents on the reaction of VES with Fe (III) was also examined. Experimental results indicate that the apparent viscosity of live VES-based acids (20 wt% HCl, 4 vol% VES) increased from 14 to 751 cp at a shear rate of 10 s -1 when the Fe (III) concentration was increased from 0 to 2,300 ppm, and started to decrease at higher Fe (III) concentrations. This is because of the electrical bonding between negative charged [FeCl 4 ] - groups and positive charged amine groups in VES in live acids. Both surfactants interacted with Fe (III) and precipitates, which are complexes containing iron and VES, were noted at 5,000 ppm and higher concentrations of Fe (III). On the other hand, adding a chelating agent [1:1 mole ratio to Fe (III)] reduced the apparent viscosity of the sample to no more than 40 cp at the shear rate of 10 s -1 when Fe (III) concentration is lower than 4,000 ppm, which means that the chelating agent reacted with Fe (III) and reduced interactions between VES and Fe (III). Adding a suitable chelating agent can minimize the impact of Fe (III) on VES-based acids.

It is commonly seen that water accumulation and near wellbore damage leads to the loss of production. This phenomenon had also been observed in many gas fields in Germany. Five years ago foam & scale inhibitor batch (FSIB) technique was applied but it remained successful only in few fields as only fluid pumping with chemicals was the part of this technique. Foam & scale inhibitor squeeze (FSIS), a novel technique was developed that involves natural gas pumping along with chemicals. It has been done by using high pressure mobile natural gas compressor. This technique is based on several steps during which foam water as based along with additives (like scale inhibitors, chelating agent etc.) comingled with natural gas are being pumped in the well. In final step compressed natural gas is also bullheaded to displace the pumped chemicals in to the formation. FSIS has been successfully applied to bring water flooded and damage wells (with no production) back to production. Many targets can be achieved in one job by applying this technique like: removal of water in near wellbore region, cleaning from scales, well kick-off to production in quick time after treatment (due to comingled and displaced gas and reduced hydrostatic pressure), less down time, economy and no effect of produced gas quality. This report would elaborate the difference between the two techniques Foam & scale inhibitor Batch (FSIB) and Foam & scale inhibitor squeeze (FSIS). Job procedure and benefits associated with these techniques will also be presented along field results.

The Maari Field is located 50 miles off the coast of South Taranaki, New Zealand. In this paper, we will present details of a laboratory test programme which was conducted to assist in the design of removal and mitigation treatments for flow assurance in the Maari oilfield. Main operating partner OMV initiated laboratory testing of a series of carbonate and sulphate scale dissolver and inhibitor treatments for use in the field, examining formation damage aspects potentially associated with the use of such fluids in the field. The waxy nature of the reservoir crude oil presented challenges for core flood testing, in particular the design of appropriate crude oil conditioning techniques to provide representative samples and core flood protocols to omit potential laboratory artefacts. The Maari crude oil contains heavy oil fractions, high wax content and a high wax appearance temperature. Standard field sampling, laboratory conditioning and sub-sampling methods can result in loss of light fractions through evaporation and thus a crude oil sample weighted towards the heavier molecular weight oil fractions. Also there is potential for heavy end losses due to insufficient conditioning temperature, filtering and sub-sampling. Appropriate protocols were therefore required to condition the crude oil to a field representative state for use. Heavy oil fractions within the crude oil presented challenges for conducting effective core flood tests. Oil particulates and heavy fractions can induce wax deposits and fines mobilisation effects that can be considered test artefacts obscuring formation damage test results. Alternative test methods were therefore designed to ensure the crude conditioning methods and core flood tests are as representative as possible of the oilfield whilst also providing clear and accurate formation damage assessment. This paper therefore presents a laboratory strategy designed to account for the aforementioned challenges alongside laboratory test results and subsequent recommendations for crude and core conditioning and core test protocols under similar conditions.

Bakken well activity and oil production has increased dramatically in recent years, largely because of technological advancements in drilling, completion, and hydraulic fracturing. For one North Dakota operator experiencing downhole calcium carbonate scaling in the pump and production tubing, an innovative inhibition program has been implemented and shown to reduce well scaling frequency. The new scale inhibition program utilizes a solid proppant-based additive from which the scale inhibitor gradually desorbs. With expansion of the development into new fields which exhibit lower scaling risk, the scale inhibition program was then limited to the higher scaling risk fields, reducing cost and simplifying operations. Bakken wells are completed to vertical depths of approximately 10,000 feet with horizontal laterals up to 10,000 feet and produced via multi-zone completions. The operator initially applied high concentrations of liquid scale inhibitor as an additive to fracturing fluid; nevertheless scaling remained a recurring problem. A postmortem of the failed wells was conducted to eliminate failures not directly attributable to calcium carbonate scale and to identify the factors affecting the scale deposition. The postmortem considered the method of hydraulic fracturing, pump intake pressure, scale inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure. Results of this study are detailed in paper SPE 140977 ( Cenegy et al. 2011 ). This paper continues the study and describes the subsequent scale management program initiated. It details the technology implemented and results in effecting downhole failures due primarily to scale. The paper additionally discusses the solid scale inhibitor technology selection, the inhibitor placement process and the steps taken to further optimize and manage costs of the field-wide Bakken scale inhibition program.