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Summary Waterflooding is known as an affordable method to enhance oil recovery after primary depletion. However, the chemical incompatibility between injected water and the water in the reservoir may cause the formation of mineral scales. The most effective method for managing such a problem is to use a variety of scale inhibitors (SIs) along with a waterflooding plan. It is necessary to perform a comprehensive study on the incompatibility scaling issue for the candidate‐brine/SI formulations, and also their effect on the reservoir‐rock/fluid characteristics. In this study, both in the absence and presence of polymeric, phosphonate, and polyphosphonate SIs, the scaling tendency (ST) of different brines is evaluated through experimental and simulation works. Drop‐shape analysis (DSA), environmental‐scanning‐electronic‐microscopy (ESEM) observation, energy‐dispersive X‐ray (EDX) analysis, and microemulsion phase behavior are also used to study the effect of different brine/SI formulations on the rock/fluid and fluid/fluid interactions, through wettability and interfacial‐tension (IFT) evaluation. In summary, sulfate () was identified as the most problematic ion in the formulation of injected water that causes the formation of solid scales upon mixing with the cation‐rich formation water (FW). In the case of SIs, solid precipitation was shifted toward a lower value, with more pronounced effects at higher SI concentrations. At different ionic compositions, the inhibition efficiency (IE%) of all SIs ranged from 16 to 50% at [SI] = 20 ppm and 38 to 81% at [SI] = 50 ppm. In general, phosphonates worked better (i.e., higher IE value) than polymeric SI. Measuring contact angles along with ESEM/EDX data also illustrated the positive effect of SIs on the wettability alteration of the aged carbonate substrates. In the absence of SIs, the contact angles for different brines were in the range of 70° ≤ θ ≤ 104°, whereas these values fell between 35 and 80° for systems containing 50 ppm of SI. In addition, phase‐behavior study and IFT measurement illustrated a salinity‐dependence effect of SIs on the interfacial behavior of the oil/water system.
Abstract Sour oil and gas production is commonly associated with sulfide scaling challenges originating from the produced aqueous phase. Iron sulfide (FeS) is one of the most common sulfide scales, and recent studies have shown promising dispersant chemicals are available to mitigate its deposition. In addition, successful applications have been reported in the literature, particularly from the North Sea. However, some of the limitations of these FeS chemical dispersants become evident under more severe (high H2S) sour conditions, such as those found in the Middle East, Russia and Canada. The dispersant efficiency depends on the scale particle size, and larger particle sizes usually require higher dispersant dosages. Other factors that may influence the inhibitor dosage include reactant concentrations (cations and anions), pH, salinity and inhibition time. These factors were investigated using a newly developed anaerobic experimental setup that allows the careful addition and withdrawal of fluids from a closed anoxic system. Anaerobic vessels, such as vials and tubes, are deployed equipped with septa (thin membranes). Syringes were used to infiltrate the septum with minimal interference from sulfide retention while maintaining isolation from atmospheric oxygen. Testing was performed over a sulfide concentration range from 100 to 1,000 mg/L. Higher levels of sulfide required higher loadings of scale inhibitor, essentially as a result of particle size increase. In addition, varying the salinity also had a significantly influence on the required dispersant concentration to maintain FeS suspension in solution. At lower pH condition, smaller FeS particles were produced and often inhibition was somewhat obscured by solubility effects. Also, suspending the FeS for longer periods of time required higher dispersant concentrations. More severe sour conditions exceeding 1,000 mg/L of aqueous sulfide, have a detrimental effect on the both the efficiency and economics of the FeS inhibition treatments. In addition, the current high- performance dispersants cannot be squeezed into tight formations or shales, as their high molecular weight may cause severe formation damage. For such applications, alternative inhibition methodologies are required, and non-chemical inhibition may be considered.
Abstract With the current trend for application of Enhanced Oil Recovery (EOR) technologies, there has been much research into the possible upsets to production, from the nature of the produced fluids to changes in the scaling regime. One key question that is yet to be addressed is the influence of EOR chemicals, such as hydrolysed polyacrylamide (HPAM), on scale inhibitor (SI) squeeze lifetime. Squeeze lifetime is defined by the adsorption of the inhibitor onto the reservoir rock, hence any chemical that interacts with the adsorption process will have an impact on the squeeze lifetime. This paper experimentally demonstrates potential changes to inhibitor adsorption from a polymer EOR project by demonstrating the complex interactions between HPAM and phosphonate scale inhibitors with respect to adsorption. This work presents a detailed coreflooding programme, supplemented with bottle tests, to identify the impact of HPAM on a diethylenetriamine penta(methylene phosphonic acid) (DETPMP) squeeze lifetime. A range of pH values, representing the expected inhibitor injection pH, have been studied on consolidated and crushed Bentheimer sandstone. A temperature of 70°C is used throughout as it represents the likely maximum temperature at which HPAM would be applied and the typical temperature at which DETPMP would be used in squeeze applications. The results presented show that scale inhibitor application pH is key in defining the impact of HPAM on DETPMP adsorption. Neutral pH displays a reduced squeeze lifetime, believed to be due to reduction of adsorption sites by HPAM. However, this impact could be countered by injecting this type of scale inhibitor at a low pH (e.g. pH 2). Static tests performed alongside the corefloods show that even low inhibitor concentrations (as found in SI pre-flushes) are sufficiently acidic to fully precipitate the HPAM from solution, but did not impact the adsorption. This study suggests, contrary to the commonly held view in the industry that EOR polymers may negatively impact squeeze lifetime, that with the correct selection of inhibitor type and their application pH it is possible to achieve the same results as in a conventional reservoir.
Sulfide scales, such as ZnS or FeS, are not as common as carbonate and sulfate scales, but an effective way to control them has not been fully developed. Solubility of ZnS and FeS is extremely low. As a result, it does not require a great amount of metal ions to precipitate sulfide scales. Once they are deposited on the surface, it is difficult to remove them due to their low solubility. The objectives of this study are to identify more effective and efficient chemicals for prevention and removal of sulfide scale deposits and to understand the sulfide scale control mechanism of these tested chemicals. We found that carboxymethyl cellulose, which is a cellulose derivative, was an effective sulfide dispersant in our tested conditions and combining with diethylenetriamine penta (methylene phosphonic acid) increased its capability to prevent sulfide scale deposition. Moreover, the effectiveness of sulfide scale dispersing was not affected by the presence of other scales, such as barite. We also found that FeS scales were effectively dissolved using tetrakis(hydroxmethyl) phosphonium sulfate combining with D-amino acid as well as aminiopolycarboxylic acid. The dissolution rate was faster at the early stage then slow down as the dissolution reaction proceeded.
Mineral scales are a ubiquitous problem in water distribution system as well as commercial and industrial operation systems. Millions of dollars are spent throughout the world due to scale deposits in water line, boiler, cooling, membrane, etc. The common scale prevention approach is to apply scale inhibitors that kinetically inhibit the solid precipitations. Carbonate and sulfate scales are the most common encountering scale problem, but there are several threshold inhibitors controlling them effectively in various applications. On the contrary, sulfide scales, such as ZnS or FeS, are not as common as carbonate and sulfate scales, but an effective way to control them has not been fully developed. Sulfide could be naturally produced through sulfur reducing bacteria (SBR) and Fe can be provided from various corrosion processes, including microbiologically influenced corrosion which commonly take place in water and wastewater distribution system as well as oil and gas pipelines.1 The potential sources of Zn are mineral dissolution in aquifer and zinc bromide completion fluid which has been lost into the formation during drilling.2
Sulphide scales, namely iron sulphide (FeS), zinc sulphide (ZnS) and lead sulphide (PbS), are increasingly being encountered in gas/oil wells. These scales can present serious safety concerns, impair well productivity and limit access to downhole tools. There are many published research studies addressing sulphide scale removal and inhibition. However, there is an incomplete understanding of the governing processes of sulphide scale formation and prevention. Furthermore, there are contradictory results in the literature on issues such as the removal procedures and inhibition tests for sulphide scales. Therefore, the main objective of this paper is to critically review the published work on sulphide scale formation, removal and inhibition, to address the factors that control them and to discuss some of the apparent discrepancies in published experimental studies.
The review discusses the formation mechanisms of different sulphide scales in relation to the sources and levels of Fe, Zn, Pb and the sulphide species. The experimental procedures used by different researchers to evaluate sulphide scale dissolvers and inhibitors are described, along with the performance results for the chemistries tested to remove or prevent sulphide scales.
Hydrochloric acid has been shown to outperform rival chemistries for dissolving sulphide scales, however the associated high corrosion rate and H2S generation has necessitated the development of other dissolvers to overcome such drawbacks. Several dissolvers based on chelating agent chemistries combined with catalysts provided high dissolution rates, and the dissolution results and the reaction mechanisms will be discussed in some detail.
Multiple factors have been shown to play a significant role in the inhibition efficiency of sulphide scale inhibitors including pH, salinity, temperature, scale formation sequence and mechanism, and the initial concentrations of sulphide species and scaling metals. In addition, there is a developing understanding of the significance of scale inhibitor consumption in these systems.
Understanding the formation mechanism is essential for accurate interpretation of scale-related issues in the field and for providing the correct treatment strategy. A more complete knowledge of these issues will lead to the further development of reliable procedures for generating dissolution and inhibition results and consequently improving the scale dissolver and inhibitor chemistries themselves.
Al Kalbani, M. M. (Heriot-Watt University) | Jordan, M. M. (Nalco Champion) | Mackay, E. J. (Heriot-Watt University) | Sorbie, K. S. (Heriot-Watt University) | Nghiem, L.. (Computer Modelling Group Ltd.)
Summary Barium sulfate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing waterflooding. Chemical enhanced oil recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulfate coproduction behavior, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer, surfactant, and surfactant/polymer (SP) flooding cEOR processes. To aid the cEOR economic decision, assessment of the impact of cEOR flooding type on both scale management and oil recovery is performed. Reservoir simulation has been used in this study, employing homogenous and heterogeneous two‐dimensional (2D) areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of anionic surfactant and partially hydrolyzed polyacrylamide (HPAM) polymer [e.g., oil/water interfacial tension (IFT), IFT, polymer viscosity, and SP adsorption]. Assessment is made of the minimum inhibitor concentration (MIC) required to control the scale that is predicted to occur due to the changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor (SI) during squeeze treatments in the production wells is modeled. The high viscosity and more stable HPAM polymer slug reduces the mixing between the injected and the formation brines, especially with low‐salinity low‐sulfate () make‐up brine, reducing BaSO4 scale precipitation in the formation, delaying and reducing the potential scale risk in the producer wellbore compared to normal waterflooding. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion (ME) phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the waterflooding case, depending on the IFT, ME phase type, the injected salinity, and sulfate concentration. In SP flooding, low‐salinity make‐up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the injection brine salinity, concentration, and changing brine composition due to ion reactions affects the produced water rates, the number of required squeeze treatments and MIC values over time. This, then, impacts the inhibitor retention and release, which influences the treatment volumes and cost required to control scale over field life. Considering the economic impact of cEOR flood type on both oil recovery and scale management, low‐salinity SP flooding is demonstrated to be the most viable option, showing the highest positive net present value (NPV). The study shows that barium and sulfate coproduction and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities) on the oil/water IFT, on the level of chemical adsorption, and on the selected brine salinity. The severity of the scale risk is also impacted by the flood techniques used, with the extent of reservoir reactions having an effect on the MIC required to control scale and the squeeze treatment volumes required to maintain production after breakthrough.
Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations and is the base acid commonly paired with others such as hydrofluoric (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature can make HCl a poor choice. Alternatively, weaker and less corrosive chemicals such as organic acids can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids.
This review includes various laboratory evaluation tests and field cases which outline the usage of organic acids for formation damage removal and dissolution. Rotating disk apparatus results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, core-flooding, Inductively Coupled Plasma (ICP), X-Ray Diffraction (XRD), and Scanning Electron Microscope Diffraction (SEM) tests.
Due to their retardation performance, organic acids have been used along with mineral acids or as a stand-alone solution for high-temperature applications. However, the main drawback of these acids is the solubility of reaction product salts. In terms of conducting dominant wormhole tests and low corrosion rating, organic acids with low concentrations show good results. Organic acids have also been utilized in other applications. For instance, formic acid is used as an intensifier to reduce the corrosion rate due to HCl in high-temperature operations. Acetic and lactic acids can be used to dissolve drilling mud filter cakes. Citric acid is commonly used as an iron sequestering agent.
This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically, in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.
Abstract Iron sulfide scales of different forms exist in sour oil/gas producing wells as well as seawater injection wells. Traditionally, they are dissolved using HCl and other inorganic acids. In the past decade, a tetrakis (hydroxymethyl) phosphonium sulfate (THPS) and ammonium chloride blend have shown potential to dissolve FeS scales. The objective of this study is to optimize the dissolver composition and treatment time for the dissolution of FeS using different concentrations of THPS and NH4Cl at 150 and 300°F. This work also evaluates the thermal stability of the blend at 350 and 400°F using aging cells. The optimum blend composition and treatment time at high pressure-high temperature (HPHT) conditions is not available in literature. The thermal stability of THPS and NH4Cl is unknown at a temperature greater than 300°F. Bottle tests at 150°F helped optimize the THPS and ammonium chloride blend composition and treatment time. 10 cm dissolver solutions prepared at concentrations of 0.1 to 1 mol/L THPS and 0.25 to 1.5 mol/L NH4Cl were added to 0.1 g FeS. An Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) analysis of the supernatant solution at 1, 4, 8, 12, 24, 48, and 96 hours revealed the kinetics of the dissolution process. The morphology of the undissolved iron sulfide particles was studied through a Scanning Electron Microscope (SEM). Thermal degradation experiments were performed in an OFITE aging cell and analyzed using Fourier-transform Infrared Spectroscopy (FTIR). At 150°F, a blend of 0.5 mol/L THPS and 0.5 mol/L NH4Cl proved to be the optimum combination for the dissolution of iron sulfide scale, dissolving 7,484 ppm of the iron from iron sulfide. Increasing the concentration beyond these values does not result in significant improvement in the solubility of the scale. The optimal time for treatment was found to be 48 hours for the optimum blend of THPS and NH4Cl. HPHT testing in an autoclave with hypoxic conditions showed similar characteristics to the bottle tests. Ammonium chloride was proved to be effective in a field setting. However, it was shown that adding NH4Cl to THPS is not very effective at 300°F. There was an improvement of 35% in the iron sulfide dissolution when 1 wt% NH4Cl was added to 0.2 mol/L THPS at 300°F. In contrast, the scale solubility increased by 2.7 times when the same blend was used at 150°F. At 300°F, the 0.2 mol/L THPS and 0.2 mol/L NH4Cl blend dissolved 40% more iron sulfide than at 150°F. SEM studies showed the presence of vuggy balls of iron sulfide particles after reaction with the blend instead of the original smooth surface. THPS was completely degraded to THPO and BMPA at 350 and 400°F. This work provides an investigation of the kinetics of iron sulfide dissolution (FeS) using the THPS and NH4Cl blend. It optimizes the blend composition and treatment time, at 150°F. Autoclave experiments were conducted at hypoxic conditions to mimic field treatment. A morphology study of the iron sulfide scale after treatment with the THPS and ammonium chloride blend was not done before. Thermal stability evaluation along with the dissolution study fills the gaps in the literature and provides an optimized solution for well treatment.
Abstract Iron sulfide (FeS) and zinc sulfide (ZnS) scales have been observed in many sour oil and gas wells. FeS often forms alongside other scales such as calcium carbonate and barium sulfate and such scales can be removed using chemicals like hydrochloric acid (HCl) and chelating agents. However, there are several drawbacks associated with the FeS removal by acid. For example, HCl acid, which outperforms other dissolvers has a high corrosion rate and generates hydrogen sulfide (H2S) gas as a byproduct. Other dissolvers, including chelating agents, often have low dissolution rates. Therefore, FeS inhibition is preferred as a strategy rather than allowing it to form followed by its removal. The objective of this paper is to investigate the inhibition efficiency of various inhibitors for preventing FeS and ZnS deposition. Different scale inhibitor (SI) chemistries have been examined over a wide range of parameters, including temperature, salinity, pH and concentrations of Fe, Zn and sulfide. Static formation and inhibition experiments were conducted and the progress of the reaction was monitored by inductively coupled plasma (ICP) analysis and pH. In addition, the inhibitor consumption in sulfide scale solutions has also been investigated; i.e. the inhibitor concentration has been monitored during the sulfide inhibition process to determine the role and fate of the SI itself. Polymeric scale inhibitors, including phosphino polycarboxylic acid (PPCA), showed a high inhibition efficiency for ZnS in different salinity and temperature conditions. On the other hand, some polymeric scale inhibitor that prevented the deposition of ZnS completely failed to inhibit FeS. It was found that, in mixed FeS and ZnS systems where both sulfide scales deposited, the precipitation of FeS had a negative impact on the inhibition efficiency for ZnS. By analogy, the FeS formation can affect the inhibition efficiency for other scales such as calcium carbonate and barium sulfate. In addition, in our SI consumption experiments we found that the scale inhibitor was consumed in ZnS solutions while there was no decrease (no SI consumption) in the scale inhibitor concentrations in FeS solutions. Based on these results, we demonstrate that it is easier to inhibit ZnS rather than FeS under the same conditions. The presence of FeS had a negative impact on the performance of the scale inhibitor for ZnS and similar effects might occur in FeS/conventional scale systems. For the first time in a sulfide scaling system, this work examines if the scale inhibitor remains at its original dosage in solution or if it declines. There were two distinct behaviors, the scale inhibitor was consumed in ZnS but not in FeS solutions.
Abstract Calcium sulfate scale precipitation is a challenge especially during stimulation treatments. The main objective of this study is to mitigate calcium sulfate precipitation during fracturing treatment. With high sulfate content in source/mixing water up to 2,000 parts per million (ppm) and excessive of total dissolved solids (TDS) formation water that can reach 60,000 ppm calcium. An experimental study was conducted at the reservoir downhole temperature of 280°F to evaluate the formation water compatibility with source water wells used for fracturing fluids. The sulfate content varied in the fracturing fluids up to 2,000 ppm. This paper addresses: the scaling tendency of water-water interaction; the efficiency and minimum inhobitor concentration of three commercial calcium sulfate scale inhibitors; the stability of high sulfate fracturing fluids at 280°F (138°C) with scale inhibitors. This study indicated: water-water compatibility tests reinforce the mineral risk assessments findings for calcium sulfate scales, scale inhibitors were effective to prevent scale deposition when added at 1.5 gpt to the source water. The high pH-fracturing gelled fluids must be prepared using relatively low sulfate water (SO4 ≤ 500 ppm). The scale inhibitors, when added to the high pH-fracturing, gelled fluids at minimum inhibit concertation will not negatively affect the polymer gel rheology and adhesion. The study set guidelines to prevent calcium sulfate scales issues during fracturing jobs with incompatible source and extreme salinities formation water. The lesson learned exhibits an effective practice to maximize treatment efficiency and minimize formation damage that could be induced during fracturing.