Maintaining overall asphaltene stability is imperative for a successful flow assurance treatment program. However, complex interactions between the polar asphaltene fraction and other components in crude oil or reservoir minerals makes the stability assessment extremely challenging. These interactions can contribute towards the precipitation and subsequent deposition of unstable asphaltene clusters comprising of impurities such as paraffin, polar organics, and inorganic mineral composites. This study investigates the impact of inorganic salts and minerals on asphaltene stability and inhibitor performance efficiency.
Four problematic crude oil samples having asphaltene deposition issue along with its field deposits were analyzed. Primary characterization of oil samples was conducted by measuring physicochemical properties. Crude oil and deposit samples were further evaluated by performing multiple compositional analyses like Fourier Transform InfraRed (FTIR) Spectroscopy, Carbon Chain Distribution (CCD), and X-Ray Fluorescence (XRF). Furthermore, asphaltene inhibitor performance efficiency was measured by carrying out both dispersion test analyses.
Primary characterization of crude oil samples did not suggest any anomalous behavior indicative of unstable asphaltene fraction. However, the solid field deposition in the production and flow-lines were observed. Therefore, further analyses of the oil as well as the solid deposits was necessitated. The analyses revealed unusually high concentration of inorganic impurities co-precipitating out with the asphaltene fraction. In general, polar nature of asphaltene induces van der Waals force of attraction between permanent dipoles (Keesom), induced dipoles (London dispersion), and permanent with induced dipoles (Debye). Paraffin and polar organic fractions associate with asphaltene through van der Waals forces and reduces the active polar sites available for the inhibitor to interact with. Moreover, presence of ions within the salts and inorganic minerals introduce ion-ion or ion-dipole interactions, which are considerably stronger than the van der Waals forces. Thus, these interactions with ionic salts and minerals interfere with the inhibitor-asphaltene interactions to a greater extent and consequently reduces the inhibitor performance efficiency significantly within laboratory screening methods.
This study, for the first time, highlights detailed contribution of impurities, specifically of ionic salts and minerals originated from drilling and completion fluids or reservoir minerals, on the overall asphaltene stability and inhibitor performance efficiency. The molecular forces arising due to co-precipitation of organic and inorganic minerals were observed to impact the asphaltene inhibitor performance considerably. Therefore, it is important to comprehend the compositional and elemental content of both crude oil and field deposit samples and accordingly select asphaltene testing methodology and modify the asphaltene inhibitor chemistry.
Traditional test methods to evaluate dispersion and inhibition of paraffin wax, which are mainly based on wax gelation and deposition, often fail to distinguish and differentiate between classes of chemistries at a reasonable resolution. Recommended products based on such lab screenings sometimes have a difficult time proving success in the field. The rush for oil production from unconventional shale plays in North America create a need for quick and elaborate testing to effectively evaluate new products for prevention and remediation of known paraffin wax issues. This paper will present a progress made in this area.
For our studies a model oil system was used, which consists of field wax deposit dissolved in kerosene. Testing with a model oil allowed us to focus on the chemistries that are effective against paraffin chains known to cause issues. Several different testing conditions were used to push the ability of the chemistries to function. Light scattering was used to monitor transition from turbidity to sedimentation of paraffin wax from bulk solution under static or dynamic conditions. A total of twelve compounds from three classes of polymers and three classes of surfactants were used in treatment of these oil systems.
With this new lab testing methodology, we have been able to discover new insights on the chemistries used for paraffin wax dispersion and inhibition. In contrast to methods which only measure the end point, light scattering and transmission methodology provides system details at time intervals of 30 sec or higher. The method also allowed us to differentiate chemistries based on their impact on the separation index and sedimentation rate of targeted paraffin chains under stressed conditions by forced precipitation. It was found that certain classes of chemistries are more suited for dispersion and inhibition of waxy condensates once system passed the critical point, while others fail over time. This new approach is fast and versatile and must be used as part of a suite of lab and field screenings for product development and recommendation.
New methodology based on light scattering and transmission of oil systems can provide details not seen before on colloidal stability or instability of waxy crudes under stressed conditions. The method gives an even greater insight to how different chemistries function to mitigate known paraffin issues. Quantitative and reproducible data are obtained allowing faster screening of various chemistries and enhancing product development for new and aging fields.
Da Silva de Aguiar, Janaina Izabel (Clariant) | Pimentel Porto Mazzeo, Cláudia (Clariant) | Garan, Ron (Clariant) | Punase, Abhishek (Clariant) | Razavi, Syed (Clariant) | Mahmoudkhani, Amir (Clariant)
Recent studies revealed that solids from lab-generated deposits often exhibit compositional differences from those of field deposits, pointing to a more complex fouling process in field operations. The objective of this work was to understand and apply knowledge from field deposit characteristics in order to design and conduct laboratory experiments which yield solid deposits with comparable compositional fingerprints. This approach allows a more objective and reliable product development and recommendation strategy to be adopted for increased success in the field applications. First, oil and deposit samples from an offshore field was characterized. Second, samples of the asphaltenes extracted from oil (AEO) and from the deposit (AED) were characterized based on solubility using an Accelerated Solubility Test (AST). A customized Asphaltene Dynamic Deposition Loop (ADDL) was used in this study to simulate the precipitation and deposition of asphaltenes from the crude oil. Crude oil used in the tests was from the same well where the deposits were collected. ADDL tests were conducted at high temperature and pressure and the composition of the collected deposit from this test was compared with the deposits from the field. At last, Light Scattering Technique (LST) was applied to screen asphaltene inhibitors (AI). Four candidate chemistries were tested on LST. To confirm the efficiency, the high performer was tested on ADDL under dynamic conditions. Deposits collected from the ADDL were characterized and results showed a high degree of similarity to the field deposit. AI1 was evaluated by ADDL and it decreased the deposition in the filters by 60% and 84% at 1000 ppm. This product was selected to be tested in the field and a plant trial is ongoing.
A major shale producer in North America with established oil and gas production was facing challenges with severe paraffin deposition in downhole tubing and flowlines. Since chemical recommendations based on traditional screenings failed to deliver adequate inhibition, the operator turned to a costly remediation program to maintain production. We aimed to revisit the case, do a root cause analysis, and look for a potential chemical solution for cost savings. The field deposit obtained from the producer proved to be quite complex and introduced limitations with our current internal HTGC method for carbon chain analysis. Upon analysis, components present in the sample were found to exceed the solidity limits of the carrier system, carbon disulfide (CS2) and would precipitate out of the solution and form a two-phased system. These components were believed to be higher molecular weight carbon chains (HMWC) above C70+ at a high enough concentration to exceed the solvents solubility limit. This was the first time encountering such a sample in our experience. A systematic approach was applied to isolate the insoluble HMWC and further outsourced analysis. A MALDI-TOF and High-Resolution Carbon-13 NMR was utilized to confirm the presence of C90+ chains within the deposit at a high enough concentration to have a trimodal paraffin distribution system. To our knowledge, this is the first time a trimodal system has been documented.
As shale exploration has become more prevalent, producers are encountering more cases of shale oil with a high amount of paraffin content. With this introduction of paraffin wax, there are a number of challenges arise that include deposition of paraffin wax at well bore, in production tubings, chokes & valves, flow lines, separator and storage tanks which extend further down the pipelines to the refineries. With the growing demands in the global oil market for production optimization and cost reduction there is an increasing pressure for producer's and service companies to accelerate innovation in flow assurance and to deliver necessary best in class performance. While there have been great strides in treatment knowledge and method development in order to screen and optimize products under laboratory flow conditions, none are capable of simulating and measuring wax deposition under static or quasi-static conditions. These normally occur during annular flow, shut-in times, batch production and storage period. Our aim was to develop a simple, yet versatile technique to study deposition and control for dilute and semi dilute paraffin wax suspensions in condensates and model crudes comprising field paraffin waxes.
Over the last few years, we have successfully treated several production wells across Eagle Ford shale play in South Texas. Shale oils are highly paraffinic with many featuring wide distribution of paraffin molecules that can extend to C100 carbon chains. Consequently, this creates a major risk of organic scale that can deposit in production and flow lines, storage tanks, and process units. With current downturn in global oil & gas market, need for production optimization and for cost reduction urges producers and service companies to work in collaboration and accelerate innovation in chemical treatment strategies. This work is aimed to develop a more in-depth knowledge on how wax formation and gelation of various shale oils are impacted by their chemical composition and production regime and how to select and deploy best chemical additive for ultimate performance during field operation.
We have characterized reservoir hydrocarbons chemistry by common industry practices and studied their wax formation behavior through use of advanced rheology techniques. Measurements of dynamic modulus, gelation point and yield stress at simulated temperature profile that mimic production conditions gave detailed perspective of crude tendency for wax deposition. Information then was plugged into a screening program which includes major classes of polymeric materials and a few selected surfactants. We used a cumulative index to rate performance of various chemistries based on composition of oil samples and actual field conditions.
Viscoelastic properties and gelation behavior of paraffin crystals from ten different crude oils in the Eagle Ford are determined. Despite some compositional differences among the samples, the similarity of their micro and macro physical properties is quite remarkable. Wax formation is highly affected by the presence of high molecular weight paraffin molecules, but gel structure and strength trends were found to be quite complex. We made an attempt to explain the above observations by paraffin fingerprinting. Then we established correlation between structure and performance of chemicals based on targeted paraffinic groups. Identifying key indices for wax control products allowed development of more efficient chemical additives for wax control and mitigation.
To the best of our knowledge, this is the first comprehensive study that presents details of chemical composition, rheological properties, and wax formation characteristics of representative shale oils from Eagle Ford. This study adapted a novel approach by incorporating best field practice data into a product evaluation program and to further improve wax treatment strategies with benefits to shale operators and producers. Viscoelastic models exhibit good potential for accurately capturing the details of wax formation pattern. Lessons learned and proposed approach can be applied in other unconventional developments where wax precipitation and deposition is a major challenge.
One of the challenges in operating oil & gas wells with production of very saline formation water is preventing and controlling the onset of scale precipitation and deposition. The reason is that operators often face scale deposits of not only common minerals such as carbonates and sulfates, but also much more significantly sodium chloride (halite). Halite scales in oil and gas wells can significantly reduce production and generate severe safety issues. Current industry practice includes fresh water injection for halite control and application of classical inhibitors aimed for reducing common scales independently. The operation cost of fresh water injection is getting higher, which makes the halite inhibitor more attractive. Poor stability and brine incompatibility, however, have made viability of such inhibitors to be fairly limited. Need for a multifunctional scale inhibitor to combat both halite and common scales is of paramount significance in optimizing operational costs.
Multiple methods had been involved in the development and investigation of the multifunctional inhibitor for controlling both halite and common scales. The static jar tests were used to evaluate the halite inhibition performance of the polymer component of the multifunctional product. Thermal stability was examined for the new polymer by thermogravimetric analysis and assessment of the thermally aged polymer. Divalent ion tolerance was also checked for the new polymer during the development of the multifunctional product. For the developed multifunctional scale inhibitor, kinetic turbidity test was undertaken to investigate its kinetic behavior to prevent halite formation at different concentrations, temperatures, and brine compositions. Meanwhile, dynamic scale loop was adopted for evaluation of the product to prevent formation of the common carbonate and sulfate scales.
A unique polymeric scale inhibitor was developed based on a carboxylate-sulfonate copolymer which exhibited excellent hydrolytic and thermal stability up to 350°F (177°C) and was tolerant to waters containing high levels of divalent metal ions. The development was targeted on inhibition of multiple types of scales particularly halite. The product showed successful performance on halite control in both lab experiments and the field trial. Besides, the product exhibited efficiency to mitigate the regular carbonate and sulfate scales in lab experiments and field monitoring. In this paper, we will present and discuss benefits and limitations of new chemistry in comparison to other known methods.
This work provides an in-depth overview of challenges in managing halite and regular carbonate and sulfate scales in salt-saturated formation brines. It will also present a novel multifunctional polymeric scale inhibitor that is effective in managing such mineral scales. Impacts on reducing fresh water injection and improving production efficacy will be discussed for the benefits of operators and engineers.
During hydraulic fracturing operations in oil wells, the equilibrium balance of the crude oil is disrupted once high-pressure fluids are injected into the formation. Fluid temperature is often less than reservoir temperature, and if the formation is cooled below the cloud point, paraffin precipitates may deposit in the formation pores and faces as fractures develop. For paraffin-rich reservoirs, such as shale oil, damage caused by wax deposition at the fracture skin can cause decreased production, slow or hard to clean up wellbores, or failure to achieve predicted maximum recovery.
Developments in horizontal drilling and hydraulic fracturing during the past decade provided the industry with a versatile tool that utilized fracturing fluids as a carrier to deliver chemical additives in the form of liquids or solids deep into the reservoir. Chemistries, such as scale, wax and asphaltene inhibitors, are impregnated or infused in porous solids and placed into fractures during the fracturing job, which can provide long-term well protection and production control. Water-soluble additives can be easily formulated within these fluids and/or delivered via slow-release solid products, but the delivery of water-insoluble additives are difficult on an equivalent base. Non-polar additives are not going to be released from solid carriers since the water cut is relatively high within one to four weeks of a hydraulic fracturing job. The risk of organic deposition persists if minimum inhibition concentration of chemical additive is not attained during and after the job.
The scope of discussion in this paper will largely focus on water-dispersible systems, in particular to colloidal microdispersion, since they are the most prevalent type of dispersions found to be viable for hydraulic fracturing applications. A methodology is presented that demonstrates the advantages of water-dispersible wax inhibitors that prevent paraffin deposition from waxy crudes in the Bakken, Permian and Eagle Ford basins while complementing long-term control further provided by solid wax inhibitors.
This study adapted a novel approach by incorporating wax and paraffin control chemistries into a microdispersion system that is fully dispersible in water. In such micron-sized liquid-in-liquid or solid-in-liquid colloidal dispersed systems, active chemistries comprising polymers from poly (EVA), poly (alkylacrylate), poly (EVA-alkylacrylate), poly (α-olefine-MAA) esters/amides/imides, and selected dispersants and surfactants are brought together to deliver immediateand short-term inhibition for paraffin wax control.
With the ever-growing demand for more environmentally acceptable oilfield chemicals, classic oilfield chemistries are becoming obsolete and new chemical systems are required. Future oil production will be dominated by unconventional oil production with increased amounts of chemicals needed to further improve oil recovery with higher production rates. In addition, environmentally acceptable chemistries will be of increased significance and the use of natural product based chemicals will further ensure a more sustainable oil production.
To achieve the future requirements of environmentally acceptable surfactants for chemical enhanced oil recovery, chemistries with low toxicity and high biodegradability are needed. Renewable based fatty acid amides represent such a class of bio-based surfactants that are environmentally acceptable and show superior performance in enhanced oil recovery applications.
The following paper describes the chemical design of renewable based fatty acid amide surfactants and their use in EOR applications. Extensive phase behavior studies, salinity scans, adsorption studies, IFT measurements and surface tension measurements were performed to present the high efficiency and potential of these products for surfactant polymer- and surfactant flooding on different crude oils. Furthermore, the biodegradation and aqua-toxicity of the renewable based fatty acid amide surfactants will be discussed in detail. This new class of bio-based surfactants represents an environmentally acceptable option to the broadly used internal olefin sulfonates with superior performance, especially for carbonate reservoirs. The non-ionic character of the renewable based fatty acid amide molecule results in much less ability to adsorb on rock surfaces which allows a potential re-injection of the produced water to decrease chemical consumption. Additionally, the viscoelastic behavior of this new class of surfactants will improve the sweep efficiency during a flooding process. Overall, these multi-functional natural-based surfactants will drastically increase oil recovery rates when applied.
Wylde, Jonathan J. (Clariant Oil Services) | Okocha, Cyril (Clariant Oil Services) | Smith, Rashod (Clariant Oil Services) | Mahmoudkhani, Amir (Clariant Oil Services) | Kelly, Craig J. (Clariant Oil Services)
Iron sulfide scale can be relatively common-place in maturing oil wells and produced water handling systems. Iron sulfide can also be commonly formed as a corrosion product, due to sour corrosion resulting from H2S containing fluids being processed through carbon steel tubulars. As more sour production is brought on-stream iron sulfide continues to become more prevalent. There are few options for removing deposits of iron sulfide scales especially when it comes to choice of chemistry. This paper discusses the most commonly performed techniques for iron sulfide removal, including hydrochloric acid, organic acids and THPS, and the varying degrees of success that these chemistries have in application. Challenges using hydrochloric acid are encountered due to the potentially high yield of H2S upon dissolution of the scale, along with FeCl2 and therefore the potential of secondary deposition.
This paper provides data on the development of a new dissolver for iron sulfide. Dissolver tests were performed initially on laboratory generated iron sulfide scale to optimize the formulation. Further testing was performed on different polymorphs of iron sulfide including pyrite, pyrrhotite, troilite, marcasite and mackinawite. Furthermore, several field scales were obtained and after XRD analysis, tested with the novel dissolver chemistry. It was shown that the new chemistry significantly outperformed THPS based dissolvers (active for active) and as well as 7.5% HCl. The corrosion rate of the novel chemistry was significantly lower than inhibited HCl and commercial THPS based blends. Testing was also performed at high pressure in order to understand the influence that pressure has on dissolution rates for all the commonly used dissolver chemicals. The new dissolver chemistry has significant chelating ability for sulfide scales as well as other ‘standard’ scale types including, calcium carbonate and calcium sulfate. The new product offers an effective multi-functional solution to dissolution of heterogeneous scale deposits.
The paper concludes with a case history of field application summarizing in detail the parameters of the field deployment and various KPIs used to measure success. The application is unusual as it was performed using a continuous injection method into an online system.