In times of increasing crude oil demand, enhanced oil recovery methods, such as CO 2 flooding, are gaining interest as alternative approaches to more efficient oil extraction. In conjunction with this technology, which inevitably affects the oil chemistry, stands the pressing issue of asphaltene precipitation, which results in significant increases in operating expenses for these operations. Here, we report details of an analytical protocol that uses quartz crystal microbalance with dissipation module (QCM-D) for testing the immediate-and long-term effects of chemically modified inhibitors against asphaltene deposit growth onto asphaltene-coated carbon steel, a situation that is often encountered in oil production equipment. The inhibitors were tested within a large concentration range on model solutions of different Middle Eastern asphaltene samples. Unlike the traditionally and commonly used precipitation test, QCM-D provides accurate and time-dependent information on physicochemical processes, such as adsorption, removal, and inhibition, onto/from a desired surface within a single experiment. The results indicate that the inhibitor chemistry and, particularly, the electronic properties of the functional groups in the inhibitor molecules are central to their performance. Specifically, while non-Brønsted-acid-type additives with electron-withdrawing functional groups are ineffective toward removal of previously adsorbed asphaltenes, complex Brønsted-acid-type molecular mixtures having electron-withdrawing functional groups remove deposits at very low concentrations. However, Brønsted-acid-type additives having electron-withdrawing functional groups can also aggravate deposition above a certain concentration threshold, which is not the case for the non-Brønsted-acid-type additives. Surprisingly, the addition of a second electron-withdrawing functional group to an already electron-poor Brønsted-acid-type inhibitor was found to have an adverse effect on the inhibitor's performance. It is also shown that single-component inhibitors can compete with multicomponent systems in removal; however, they are less effective in prevention of precipitation after the removal.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWater production from gas producing wells characterized by low productivity and low reservoir pressure zones can prematurely kill wells, leading to a considerable loss in recoverable reserves. In some cases, mechanical techniques provide a viable solution for shutting off water production, although often, such a solution will create a restriction inside the well, limiting access to deeper reservoir layers. Even though chemical water shutoff chemicals and techniques are improving significantly, not many options are available to treat high temperature and low permeability reservoirs. It may prove difficult to squeeze cement slurries and different types of gels into such formations owing to constraints of particle sizes or fluid viscosity. It is a challenge to get a squeezable fluid into low-permeability reservoirs that will be effective in sealing the near-wellbore area and be able to withstand high differential pressure while producing. Another challenge is to determine a placement technique to prevent excess displacement of the treatment, to minimize further intervention into the well, to clean any residual treatment from the tubing, and to minimize water damage to highly sensitive producing layers. This paper presents successful case histories of treatments that were performed to shut off water producing layers characterized by low permeability. It describes innovative techniques that were developed for this special project. The treatments were placed using coiled tubing, and only one run was required to shut off the zones in question.
Oil producers completed with carbon steel were threatened with sweet corrosion due to early water breakthrough and the presence of carbon dioxide in the associated produced gas. In severe cases corrosion led to problems which interrupted production and put the wells in an unsafe service condition. Remediation or replacement of damaged tubing was not cost effective or not feasible. A robust corrosion inhibition program through periodic squeeze treatment was implemented. Optimized and improved through the years it provided effective protection of the downhole completion and extended well operating lifetime.
Mineral scale formation in the oil and gas industry can be detrimental to production and injection wells, and facilities yielding production losses and integrity issues. In order to manage scaling risk during operation, knowledge of production rates, GOR, WCT%, and hydrocarbon and produced water compositions along with reservoir pressure and temperature are required. Scale management relies on accurately monitoring produced water composition. In addition, the timing of changes in water composition is critical to proactively protect the production system from scaling. Preventing scale formation results in significantly reduced production loss, optimized chemical dosage, and fewer well interventions, consequently lowering OPEX and mitigating HSE risks. This paper documents advancements made since the last year publication by the authors on the real-time produced water composition measurement device. The device can automatically collect a discrete production fluid sample at the wellhead while keeping the pressure and temperature of sample constant, separating produced water from the bulk phase and measuring multiple properties: pH, alkalinity, strontium, barium, calcium, sulfate, total hardness, and total dissolve solids (TDS) at the pressure and the temperature of sampling point without degassing. It also reports the pressure and temperature of sampling point. This paper illustrates calcium automated measurement properties developed and a validation of the laboratory prototype by testing the device with four produced water samples from different formations: i) Permian Basin, ii) Bakken, iii) Eagle Ford; and iv) synthetic produced water from an oil field in Abu Dhabi. Results show excelent performance of the device for calcium measurement. For example, the mean of the device measured value for calcium based on internal calibration, was 42.84 mg/l with a standard deviation of 0. 084 compared with the laboratory reference method ICP-OES measurement of 42.63 mg/l, which shows very accurate measurement of calcium. This paper presents the reliability and repeatability of the device in addition to the results accuracy compared with ICP-OES and traditional laboratory analysis methods. The results obtained from production fluids were promising. Laboratory validation is the last step before field testing the device. The success of the laboratory validation stage is crucial as the device progresses through final design changes ahead of field trials. Measuring produced waters with different salinities promote the device reliability and fills the gap between synthetic water composition measurement in laboratory and the field trial. The device was developed to enhance reliability of water properties measurements, provide real-time measurements, and reduce downtime and costs associated with workovers, interventions, and sampling.
A new generation of sophisticated wells are to be drilled in a giant offshore field in Abu Dhabi. These extended reach wells will reach and produce remote areas of the field from artificially built islands. The first maximum reservoir contact (MRC) pilot well was drilled successfully with 20,000 ft total depth and a 10,000 ft producing interval completed with inflow control devices (ICDs). The well started producing dry oil at reasonably high flow rate and uniform contribution from each ICD compartment. After a relatively short period of dry oil production water break-through occurred and started causing unexpected downhole flow assurance concerns, especially at the locations of the ICDs. Production logging along with caliper data showed severe corrosion around water producing ICD nozzles and high gamma ray readings in the water producing intervals, suggesting that scale had precipitated behind pipe either in the near wellbore rock (believed to be unlikely based on the history of scale precipitation in the field) or on the outside of the completion (thought to be more likely). An investigation was launched to determine the cause of the corrosion around the ICD nozzles and improve understanding of the influence of ICD flow dynamics on scale deposition and material corrosion, with the objective of developing a suitable mitigation method for scale and corrosion in future MRC/ICD wells. The study results showed that high wall shear stress developed in and around the water producing ICD nozzle area are at the origin of the corrosion in the pilot well, and that low-to-moderate wall shear stresses on and around the wire-wrapped screen sections of the ICDs could be the cause of the scale deposition. Consequently, the completion design for future wells with ICD completions has been revised to mitigate the risks of flow induced corrosion. This paper will present results of the laboratory study into the influence of ICD flow dynamics on corrosion rates and mineral scale precipitation and discuss strategies for mitigating both concerns via the design of the ICD.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.