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In many operations worldwide, surface waters are injected into producing formations to enhance oil recovery. The types of surface waters used range from seawater (salt water) to lake water (brackish) to river water (fresh water). Surface water must be treated to remove undesirable components before injection. Treatment of surface water for injection requires a specially designed system made up of various components to remove or control any contaminants in the water. The system is engineered to perform the required treatment in the most cost-effective and environmentally sensitive manner. A typical system is shown in Figure 1. Commonly used methods for removal or control of these contaminants are discussed in this section. Surface waters normally contain suspended solids particles that, if injected into the producing formation, will plug the injection well. The type, concentration, and particle-size distribution of suspended solids in water will vary depending on the source of the surface water.
Multiple types and sources of water streams are encountered in oil and gas operations; the two primary ones are produced and surface water. Produced water is the brine that comes from the oil reservoir with the produced fluids; surface water encompasses fresh (river or lake) and saline (seawater) sources. Water sources are treated for disposal, injection as a liquid, or injection as steam with three types of facilities. Produced water is treated in offshore operations for overboard disposal or injection into a disposal well, but when onshore, it is treated for surface disposal, liquid injection, or steam injection. In all instances, the produced water must be cleaned of dispersed and dissolved oil and solids to a level suitable for environmental, reservoir, or steam-generation purposes. Surface water is treated offshore for liquid injection and onshore for liquid- or steam-injection purposes. In all instances, the surface water must be cleaned of dispersed and dissolved solids to a level suitable for reservoir or steam-generation purposes. In oil-producing operations, it is often desirable to inject water or steam into the formation to improve oil recovery. Water injection for this purpose is called a waterflood; when properly implemented, it will maintain reservoir pressure and significantly improve the oil recovery vs. primary production. Steam injection, known as a steamflood, will reduce the viscosity of oil and further enhance the oil recovery. See the chapter on Steam Injection in the Reservoir Engineering and Petrophysics volume of this Handbook. In offshore areas, governing regulations specify the maximum hydrocarbon and solids content in the water allowed in overboard discharges. Some studies have estimated that during the life of a well, 4 to 5 bbl of water are produced for every barrel of oil, making this fluid the largest volume of produced product in the oil and gas industry. This chapter discusses the equipment and design criteria used in common water-treatment systems for disposal or injection. In addition to the removal of dispersed or dissolved hydrocarbons and solids, the water-treatment engineer may be concerned with chemical treatment, material selection, and solids disposal, which are also covered. Produced water typically enters the water-treatment system from a two- or three-phase separator, free-water knockout, gun barrel, heater treater, or other primary-separation-unit process. This water contains small concentrations (100 to 2000 mg/L) of dispersed hydrocarbons in the form of oil droplets. Because the water flows from this equipment through dump valves, control valves, chokes, or pumps, the oil-particle diameters will be very small ( 100 μm). Treatment equipment to remove dispersed oil from water relies on one or more of the following principles: gravity separation (often with the addition of coalescing devices), gas flotation, cyclonic separation, filtration, and centrifuge separation.
Accelerators speed up or shorten the reaction time required for a cement slurry to become a hardened mass. In the case of oilfield cement slurries, this indicates a reduction in thickening time and/or an increase in the rate of compressive-strength development of the slurry. Acceleration is particularly beneficial in cases where a low-density (e.g., high-water-content) cement slurry is required or where low-temperature formations are encountered. Of the chloride salts, CaCl2 is the most widely used, and in most applications, it is also the most economical. The exception is when water-soluble polymers such as fluid-loss-control agents are used.
In this study, several process alternatives for the permanent sequestration of carbon dioxide (CO2) as solid carbonates are evaluated. Although the formation of mineral carbonates is thermodynamically favorable, it does not occur significantly because of kinetic limitations and the formation of products that hinder the evolution of the process. In the complete paper, the authors propose biomimicking approaches to precipitate solid carbonates while limiting the amount of energy required or using the byproducts to generate valuable materials. Permanent sequestration of CO2 as solid carbonates is a feasible solution to the increased levels of CO2 in the atmosphere. Mineral carbonation--the process of capturing CO2 in the atmosphere in the form of solid carbonates through the reaction of CO2 with silicates--is a spontaneous, thermodynamically favorable process.
This paper considers some of the challenges and learnings associated with the application of chemicals for preservation of coated pipe/flowline for a major liquefied-natural-gas (LNG) project in Australia. This includes a comparison of the effectiveness of biocide and oxygen-scavenger chemistries for treating seawater. The complete paper also discusses monitoring philosophies and the unique approach taken in designing and optimizing the chemical-injection system to address the environmental and technical challenges of this project. Hydrostatic testing (gauge testing) is undertaken before commissioning new pipelines as a requirement to confirm the global integrity of an installed pipeline system that will carry fluids (gases or liquids) under pressure. Pressurization can be performed with gases such as air, nitrogen, and natural gas, or petroleum products or water.
A new downhole-tool-based abandonment system was developed and deployed successfully on four wells for a major operator on a field in the North Sea. The operations were executed with each well taking less than 18.5 hours to secure. The successful operation saved the major operator considerable time and expense by eliminating the need for cutting and pulling the 10¾-in. Service companies were challenged by a major operator to create a solution to set a barrier against the overburden and to circulate OBM out of the annulus between the 10¾- and 13⅜-in. The first stage of the operation was to run a perforation gun loaded for 1 ft with 18 shots/ft (spf) of a proprietary abandonment charge (single-casing perforation gun) to immediately below the wellhead at 475 ft.
To increase the oil recovery in the Albacora field, significant water injection is required that was not considered in the initial project-development phases. Technical and economic constraints do not allow the use of conventional seawater-injection plants because current production units have no area available to implement a conventional water-injection system. Application of subsea raw-water-injection (SRWI) systems in the field involved challenges that required a detailed and systematic analysis to evaluate the technical feasibility and establish requirements for implementation. This alternative enabled seawater to be injected into the reservoir with minimum treatment by use of equipment installed on the seabed. In some offshore fields, mainly mature fields, the addition of conventional technologies to topside facilities can constrain the use of seawater injection.
Despite the lack of freshwater resources in the Arabian peninsula, fresh water is still used in unconventional-resource operations there. Seawater, however, is plentiful and could substitute for fresh water. The high salinity of seawater raises many chemical challenges in developing design criteria for fracturing fluids. The oil and gas industry faces many challenges, including the availability of fresh water for making fracturing fluids, especially in the Arabian peninsula and other arid regions. Using seawater to make fracturing fluid can help address several obstacles and reduce costs.
Southwick, Jeffrey G. (Shell Global Solutions Intl., B.V.) | van Rijn, Carl (Shell Global Solutions Intl., B.V.) | van den Pol, Esther (Shell Global Solutions Intl., B.V.) | van Batenburg, Diederik (Shell Global Solutions Intl., B.V.) | Azhan, Arif (PETRONAS Research Sdn Bhd) | Kalantar, Ahmadanis (PETRONAS Research Sdn Bhd) | Zulkifli, Nazliah (PETRONAS Research Sdn Bhd)
Summary A low-complexity chemical flooding formulation has been developed for application in offshore environments. The formulation uses seawater with no additional water treatment beyond that which is normally performed for waterflooding (filtration, deoxygenation, etc.). The formulation is a mixture of an alkyl propoxy sulfate (APS) and an alkyl ethoxy sulfate (AES) with no cosolvent. With seawater only (no salinity gradient), the blend of APS and AES gives substantially higher oil recovery than a blend of APS and internal olefin sulfonate (IOS) in outcrop sandstone. This formulation also reduces complexity, increases robustness, and potentially improves project economics for onshore projects as well. It is shown that the highest oil recovery is obtained with surfactant blends that produce formulations that are underoptimum (Winsor Type I phase behavior) with reservoir crude oil. Also, these underoptimum formulations avoid the high-injection pressures that are seen with optimum formulations in low-permeability outcrop rock. The formulation recovers a similar amount of oil in reservoir rock in the swept zone. Overall recovery in reservoir rock is lower than outcrop sandstone due to greater heterogeneity, which causes bypassing of crude oil. A successful formulation was developed by first screening surfactants for phase behavior then fine tuning the formulation based on insights developed with corefloods in consistent outcrop rocks. The consistency of the outcrop is essential to understand cause and effect. Then, final floods were performed in reservoir rock to confirm that low interfacial tension (IFT) is propagated through the core. Introduction Chemical flooding alkali-surfactant-polymer (ASP) and surfactant-polymer (SP) uses surfactants to reduce the IFT between oil and brine to very low values so that residual oil saturations in porous media can be reduced to less than 1% in the swept zone (Pope 2011). Many laboratory studies have developed successful formulations giving high oil recovery with a wide range of oil types and reservoir conditions. These studies have led to successful field pilots, but very few of these pilots have matured to commercial production.
Amir Rashidi, Mohammad Rashad (PETRONAS Research) | Dabbi, Edgar Peter (DHI Water & Environment) | Abu Bakar, Zainol Affendi (PETRONAS Research) | Misnan, M Shahir (PETRONAS Research) | Pedersen, Claus (DHI Water & Environment) | Wong, Ka Yee (DHI Water & Environment) | M Sallehud-Din, M Taufik (PETRONAS Research) | Shamsudin, M Azim (PETRONAS Research) | Wo, Shaochang (PETRONAS Research)
PETRONAS has identified a large gas field as a potential CO2 storage reservoir in offshore Sarawak. Using the Carbon, Capture and Storage (CCS) concept, the plan is to inject CO2 into the reservoir for permanent storage with the purpose of mitigating the contribution of CO2 emissions to global warming. An important aspect of CCS is the Measuring, Monitoring, and Verification program, which is needed to ensure safe CO2 injection and storage. This includes understanding of the potential risks associated with leakage of stored CO2. This study focuses on the risk and impact of the CO2 once it escapes the overlying sediments and enters the marine environment.
To describe the behavior of leaked CO2 in the marine environment, it is important to understand the ambient flow conditions at the identified area that would govern the advection and dispersion processes in the seawater column. Hence, long-term 3D-hydrodynamic modelling is conducted to describe seasonal and inter-annual variations of hydrodynamic conditions at the area of interest. Supplementing the flow model is the coupled physical-chemical reactions that will occur if CO2 escapes into the seawater. As CO2 bubbles ascend in the water column, their volume changes because of gas dissolution and reduction in hydrostatic pressure. Additionally, as CO2 gas dissolves in seawater, concentration of the Dissolved Inorganic Carbon (DIC) increases, which in turn leads to reduction of pH in the seawater. Thus, the risk and effects of CO2 leakage to the marine environment will be reflected by reduction of the pH from its natural variation. Scenario of CO2 seepage from plugged and abandoned (P&A) well was simulated based on hypothetical leakage rates derived from previous studies.
Far-field modelling results of CO2 seepage from the P&A well suggest that no CO2 gas would reach the surface and escape into the atmosphere. The CO2 would dissolve rapidly above the seabed. Any reduction in pH values within the far-field is predicted to be within the natural variation of the seawater acidity with the varying climatic conditions. To fully capture the near-field dispersion effects, additional finer resolution modelling was performed for three representative climatic periods (or monsoons). Results suggest that the near-field plume where pH falls below 6.5 (threshold limit based on Malaysia Marine Water Quality Criteria and Standard) is usually confined within 100 m radius but may extend to 200 m from the leakage source. However, the near field model also confirms rapid dissolution of CO2 gas within the first 5 m water column above the seabed.
The study result can be used as an important input in designing X-Field's MMV operational plan in terms of optimizing sampling volume and frequencies for marine water monitoring purposes, which may result in significant operational cost reduction. Hence, similar study is recommended to be conducted with the same purpose in future CCS related projects due to its impact on the technical and economical value creation.